English Edition (6 MB pdf) - Saudi Aramco

Summer 2010 

THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY 

A quarterly publication of the Saudi Arabian Oil Company 

Contents 

Merging Tapered-in Coiled Tubing (CT) and Well Tractor 

Technologies to Effectively Stimulate Extended Reach 

Open Hole Horizontal Wells 2 

Mubarak Al-Dhufairi, Saleh A. Al-Ghamdi, Vidal Noya, 

Khaled Al-Aradi, Samer Al-Sarakbi, Ahmed Al-Dossary, 

Ernie Krueger and Dr. Norman B. Moore 

Next Generation Technologies for Underbalanced Coiled 

Tubing Drilling 11 

Shaker A. Al-Khamees, Anton V. Kozlov, Serve Frantzen, Thomas Gorges, 

Julio C. Guzman Munoz, Anthony A. Aduba and Thiago P. da Silva 

Robotics for Horizontal Image Acquisition in Ultra Slim 

Wells in Saudi Arabia 17 

Kanwal B. Singh Khalsa, Nassar A. Al-Awami, Nelson Pinero, 

Zaki A. Al-Baggal, Adib A. Al-Mumen and Ibrahim A. Zainaddin 

Stimulating Khuff Gas Wells with Smart Fluid Placement 23 

Francisco O. Garzon, J. Ricardo Amorocho, Moataz M. Al-Harbi, 

Nayef S. Al-Shammari, Azmi A. Al-Ruwaished, Mohammed Ayub, 

Wassim Kharrat, Vsevolod Burgrov, Jan Jacobson, George Brown and 

Vidal Noya 

Successful Deployment of Multistage Fracturing Systems 

in Multilayered Tight Gas Carbonate Formations in 

Saudi Arabia 34 

Hasan H. Al-Jubran, Stuart Wilson and Bryan Johnston 

Application of Hydrajetting Technology Achieves Significant 

Productivity Increase in Saudi Arabian Gas Producers 41 

Emad A. Al-Abbad 

Development and Optimization of 12” PDC Bit for Powered 

Rotary Steerable Systems in Deep Gas Drilling in 

Saudi Arabia 45 

Saeed H. AbdRab Al-Reda, Abdullah A. Al-Kubaisi, Khalid Nawaz, 

Muhammed F. Jamil, Octavio Alvarez, Baseem E. Qattawi, Jaywant 

Verma and Sukesh Ganda 

Leveraging Slim Hole Logging Tools in the Economic 

Development of Ghawar Field 58 

Izuchukwu Ariwodo, Ali R. Al-Belowi, Rami H. BinNasser, 

Robert S. Kuchinski and Ibrahim A. Zainaddin 

Saudi Aramco 

Journal of Technology

Merging Tapered-in Coiled Tubing (CT) and Well 

Tractor Technologies to Effectively Stimulate 

Extended Reach Open Hole Horizontal Wells 

Authors: Mubarak Al-Dhufairi, Saleh A. Al-Ghamdi, Vidal Noya, Khaled Al-Aradi, Samer Al-Sarakbi, Ahmed Al-Dossary, 

Ernie Krueger and Dr. Norman B. Moore 

ABSTRACT 

The Manifa field development involves one of the largest 

drilling projects in Saudi Arabia, targeting various carbonate 

reservoirs, with an extraordinary amount of extended reach 

wells (ERWs) required to meet the expected oil production 

rate, at the lowest development cost possible. More than twothirds 

of the wells fall under the extended reach drilling 

classification, and the majority of the wells have measured 

depths (MDs) between 24,000 ft and 31,000 ft. These wells 

are open hole completions where acid stimulation is greatly 

needed to overcome reservoir damage and improve the wells’ 

performance after drilling operations terminate. 

The placement of the treatment fluids requires a uniform 

distribution along the open hole section. Among the different 

techniques considered, namely bullheading, using the rig drillpipe 

and coiled tubing (CT), the last one offered the soundest technical 

and cost option. However, the CT technique alone did not show 

the ability in reaching the maximum depth in most ERWs of this 

field. Therefore, the tractor 1 was required to provide the significant 

amount of pull force needed to operate inside these long distances, 

something not seen before in open hole completions. 

The first eight well campaigns, using a combination of CT, 

a hydraulic tractor and friction reducer fluids, achieved the 

main objectives. Moreover, a new intervention world record 2 

was set when the CT bottom-hole assembly (BHA) reached 

the maximum depth of 28,257 ft inside the open hole on two 

different occasions, to place the stimulation fluids, and to 

record an injection profile. During the campaign, a total of 

41,774 accumulated footage was operated with the tractor, 

allowing over 3,400 bbls of acid to be placed in direct contact 

with the formation. As a result, the average injection rate 

increased more than tenfold, reducing the drilling 

requirements for injection wells originally projected. 

The job preparation, technology, results, learning curve 

experience and best practices are discussed in this article, 

including proposed operational enhancements. This experience 

demonstrates the feasibility of the operations with CT 

required for full zone coverage, yielding optimum water 

injection rates at the lowest development cost. 

INTRODUCTION 

One of the largest worldwide oil field developments currently 

ongoing, the Manifa field is a giant offshore field that covers 

more than 800 square kilometers (km 2 ). Located in the northeast 

part of Saudi Arabia, the field lies under shallow waters. The 

main drivers behind the Manifa field development plan called for 

meeting the production targets at the lowest development and 

operating cost, and in a safe and environmentally friendly 

manner. To achieve this, a decision was made to utilize a 21 km 

long causeway in combination with extended reach wells (ERWs) 

to reduce the need for offshore platforms 3 from 30 to 11. More 

than two-thirds of the wells were considered extended reach 

drilling by industry standards, reaching depths up to 31,000 ft. 

To maximize the oil recovery, water injection secondary 

recovery was planned for efficient sweeping of hydrocarbons 

in the reservoir. Most of the wells are water injectors drilled 

from the coast of the mainland. Oil producing and water 

injection wells are completed as open hole with a 6 1 ⁄8” 

diameter, Fig. 1. In spite of the best drilling practices utilized, 

acid stimulation was required to remove any formation 

damage created in the open hole section of the well. 

The treatment should strive to improve the injection/ 

production rates in a uniform pattern by eliminating or 

bypassing the damage. Several methods were considered to 

perform the stimulation treatment, including use of drillpipe, 

bullheading and coiled tubing (CT) equipment to convey the 

fluids. The drillpipe option is expensive and has not delivered 

good results, while bullheading experiences have not been 

effective in ensuring a uniform distribution of fluids. Using CT 

offered the best chance for uniform coverage of the open hole 

section at the lowest cost. 

The extreme length of the ERWs of the Manifa field 

presented the risk of not being able to reach the maximum 

depth of the open hole section with the CT string. Traditional 

techniques for assisting CT to reach total depth (TD) included 

the friction reducer fluids, pipe straightener, downhole 

vibration tools and hydraulic actuated tractors. Simulations of 

tubing forces in the CT with specialized software indicated 

that loads up to 8,000 lbs at the bottom-hole assembly (BHA) 

were necessary to pull the CT and reach TD in most ERWs. 

Based on this analysis, downhole hydraulic actuated tractors 

were perceived as the only viable alternative to enable the 

intervention with CT. 

Experiences with CT tractors in open hole environments 

was minimal at the time the Manifa field development started, 

with no case study similar to the expected conditions, making 

2 SUMMER 2010 SAUDI ARAMCO JOURNAL OF TECHNOLOGY

24” CSG at 365 ft EPC 

178,00#, X42; 

1. 800 G, 118 PCF 

18 5 /8” CSG at 1,127 ft EPC 

115,00#, K55; 

1. 1,100 G, 118 PCF 

13 3 /8” CSG at 5,188 ft EPC 

#, K55; 68,00#, K55, 

1. 1,028 G, 101 PCF + 560 G, 118 PCF 

2. 480 G,101 PCF 

7” TBC at 5,188 ft (8,208 ft CV) 

Landed on 09/17/2008 

28,00#, L80; 

9 5 /8” CSG at 8,052 ft EPC 

40,00#, K55; 

1. 580 G, 118 PCF + 827 G, 101 PCF 

2. 1,080 G, 101 PCF 

7” Liner at 12,998 ft EPC 

28,00#, L80; 

1. 1,100 G, 122 PCF 

• Fluid selection. 

• Fluid conveyance program. 

• Well performance evaluation. 

• BHA. 

• Health, Safety and Environment (HSE) aspects. 

INTERVENTION OBJECTIVES 

The main purpose of the intervention was aimed at: 

1. Evaluating the bottom-hole pressure (BHP) before the 

stimulation by conveying memory pressure gauges with a 

slick line. 

2. Enhancing the stimulation stage of the well by well 

placement of the treatment fluids with CT. 

3. Running the production logging tool (PLT) to evaluate the 

contribution of all the open hole zones after the 

stimulation. 

4. Evaluating the BHP after the stimulation by conveying the 

memory pressure gauges with a slick line. 

SIMULATIONS 

PD - TD 

16,385 ft 

PD: (16,380 ft CV) 

Fig. 1. Example of well completion. 

this a significant challenge for the project. The main conditions 

included that the tractor should be able to work in an open 

hole, 6 1 ⁄8” diameter borehole with caliper irregularities, tolerate 

a high H 2 S concentration environment, operate over long 

distances (up to 12,000 ft) at a reasonable speed, and still be 

resistant to large amounts of corrosive fluids. Furthermore, a 

limited choice of CT tractors was available on the market. 

The performance of the wells was also critical to the asset 

management team. Therefore, proper evaluation before and 

after the stimulation was desirable, particularly in the first few 

wells. This would provide valuable information to calibrate 

the effectiveness of the treatments and well delivery potential 

against the target production and injection goals for the field. 

The next sections of this article present the main job design 

considerations, a description of the key technical enabler, as well 

as the job planning and execution activities. It ends with a 

discussion of the results of the eight well intervention campaigns, 

with lessons learned and conclusions. 

JOB DESIGN 

The main processes to design and plan for the first eight well 

campaign involved the following: 

• Definition of objectives. 

• Simulations. 

8 1 /8”Open Hole 

(12,997 ft - 18,385 ft) 

• Selection of surface equipment. 

Proprietary software was used to evaluate the alternatives 

based on the CT outside diameter (OD) size, reach, tractor 

pull force, logistics and minimum flow rates. While a 2 3 ⁄8” CT 

OD allowed a higher flow rate, the easier logistics and 

reduced pull force required by the tractor to reach TD, 

favored the selection of 2” CT OD string. Table 1 shows 

simulation results for several well scenarios, indicating 

predicted lock-up depth vs. the TD of the well, as well as the 

required tractor force to reach TD. The simulations were 

based on a typical friction coefficient used for similarly 

completed wells in Saudi Arabia since there was no previous 

experience running CT in the Manifa field. The maximum 

pull loads from the simulations were in the order of 32,400 

lbs with 2” CT vs. 52,300 lbs with 2 3 ⁄8” CT. 

The software results also led to a conclusion that minimum 

pump rates of 1.8 barrels per minute (bpm) to 2.1 bpm for 

injection could be achieved with 2” CT OD and remain 

within the operational pressure parameters, even in the case of 

the longest well. 

SURFACE EQUIPMENT 

A conventional CT unit using an injector head, HR-580, in 

combination with a power pack rated for 250 hydraulic horse 

power (HHP), was estimated to have a capability to pull 

80,000 lbs, 35% above the maximum expected loads. For the 

longest wells, a 32,200 ft long CT string was planned to be 

used. A custom designed drop-in-drum reel was fabricated for 

the project. In addition, the conventional tool deployment 

method required risers to accommodate the entire BHA 

length. Pumping equipment was needed to provide a 2.1 bpm 

fluid rate at maximum pressures of 5,000 psi during the CT 

SAUDI ARAMCO JOURNAL OF TECHNOLOGY SUMMER 2010 3

CT Simulation Completion 

1 2 3 4 5 6 7 8 9 

TD (ft) 28,257 28,757/30,120 26,816 23,623 25,300 16,385 18,365 12,600 21,346 

OH (ft) 6,027 4,830/6,193 3,516 3,305 5,059 3,388 3,685 3,601 4,031 

7” Tubing Depth (ft) 9,100 9,494 9,710 20,302 8,231 9,705 10,481 

7” Liner Depth (ft) 22,215 23,927 23,300 20,316 20,241 12,997 14,680 8,9991 7,315 

Lock-up (ft) 15,671 15,171 13,772 17,700 16,300 16,085 15,816 No 15,764 

Lockup 

2“ Force to 11,500 11,500/14,000 13,000 4,700 7,600 500 2,300 0 5,400 

Reach TD (Lb) 

Maximum 35,422 35,065/37,514 31,457 29,513 32,366 27,228 28,393 24,640 31,365 

Pull Force (Lb) 

Lock-up (ft) 16,530 16,955 15,448 18,831 17,959 No 16,379 No 16,539 

Lock-up Lock-up 

Force to 12,500 14,500/12,500 13,500 5,500 8,000 0 2,500 0 7,000 

2 3 ⁄8” Reach TD (Lb) 

Maximum 48,4115 2,358/49,230 42,291 46,792 43,817 39,111 40,967 36,257 41,6792 

Pull Force (Lb) 

Table 1. CT reach simulation with and without tractor for 2” CT vs. 2⅜” CT 

stimulation, as well as a 14 bpm rate for treated water at a 

maximum pressure of 2,200 psi. A total of 10 tanks with 500 

bbl storage capacity, each was deemed sufficient to cover both 

stimulation and injection operations, which was continuously 

supplied directly from the sea. A slick line unit was necessary 

for running gauges during the falloff test. 

FLUIDS 

Three main acid systems were designed based on formation 

characteristics, suspected damage and previous experience in 

horizontal wells in Saudi Arabia. All systems met the 

compatibility test requirements. The most appropriate acid 

concentration selected for all the systems was 20 wt% 

hydrochloric (HCl) acid, based on the core analysis and 

retained permeability test. Due to the length of the treatment 

interval, the volumes of treatment fluids had to be optimized 

efficiently without compromising the desired results of the 

treatment. A significant volume of mutual solvent-based 

preflush fluid was proposed to displace the suspected 

hydrocarbon deposits in the near wellbore area. The preflush 

was followed by a plain 20 wt% HCl system to reduce the filter 

cake created by the drilling fluids and to create wormholes. The 

main additives in the plain acid system included a corrosion 

inhibitor and surfactant. To create an efficient network of 

wormholes, an emulsified acid system was proposed. This was 

an oil external phase emulsion formed with a 70:30 ratio of 20 

wt% HCl and diesel. The external phase of the fluid, would 

allow deeper penetration into the formation before breaking, as 

the acid started its reaction with the carbonates. 

One of the main challenges of matrix acidizing in carbonate 

reservoirs is obtaining uniform coverage of the treatment 

across the zone(s) of interest. Chemical diversion is usually 

required to ensure stimulation throughout the interval. A self- 

diverting acid system can significantly simplify the process by 

continuously injecting acid into the formation. The acid will 

viscosify in-situ and temporarily block the existing channels to 

divert itself into undissolved areas. The proposed system uses 

a viscoelastic surfactant that gels as the acid spends. This 

gelation causes temporary plugging of the acid etched 

channels to allow continuous acidizing of the unstimulated 

zone. This diversion system contains no polymer; therefore, it 

does not leave a solid residue that could cause damage to the 

rock. In addition, this diversion system was foamed with 

nitrogen to enhance its diversion capabilities in the long 

horizontal intervals. 

The design proposed a total acid concentration of 15 gallons 

per feet (gpf), while the total treatment volume would be 

divided into several treatment stages of 500 ft to 700 ft each. 

Below is the pumping sequence for each stage of the interval: 

1. Preflush 6 gpf 

2. 20 wt% HCl 3 gpf 

3. Emulsified HCl 6 gpf 

4. 20 wt% HCl 3 gpf 

5. Foamed Diverter 3 gpf 

6. Post flush 3 gpf 

Fluid Conveyance Program 

A typical treatment fluid placement followed the schedule 

shown in Table 2. 

WELL EVALUATION PERFORMANCE 

Understanding the injection profile of the water injection wells 

and the contribution of oil producers required the use of a 

PLT. Given the nature of the ERW and open hole conditions, 


Stage Depth (ft) Direction Fluid Volume (gpf) 

From 

To 

1 Casing Shoe TD RIH Preflush 6 

2 TD Top of Zone 1 POOH Emulsified HCl with diesel 6 

HCl Spearhead 3 

HCl Spacer 3 Foamed VDA (70% Foam Quality) 3 

3 Top of Zone 1 Top of Zone 2 POOH HCl Spearhead 3 

Emulsified HCl with diesel 6 

HCl Spacer 3 

Foamed VDA (70% Foam Quality) 3 

# Top of Zone (n) Top of Zone (n+1) POOH HCl Spearhead 3 

Emulsified HCl with diesel 6 

HCl Spacer 3 

Foamed VDA (70% Foam Quality) 3 

Last Casing Shoe Casing Shoe Static Post flush 3 

Table 2. Schedule for typical treatment fluid placement 

conveyance of the logging tools had to be performed with CT. 

Use of CT e-Line systems was not practical, therefore, the 

decision was made to use the Memory Production Logging 

Tool (MPLT) option. 

DESCRIPTION OF THE BHA 

Apart from the CT hydraulic tractor, the BHA used was 

conventional. The tractor was not required in two of the eight 

well campaigns. The third BHA, which was also the longest, 

included the MPLT. 

annulus, the remainder passes through the end of the BHA. 

The tractor will generate 14,500 lbs of thrust when 1,700 psi 

is present at the tool. Overall length is 27½ ft and the 

maximum expansion is 8.9”. 

The hydraulic tractor has specially designed grippers 

consisting of three continuous beams that are deformed 

outward to grip the casing or open hole, Fig. 3. The three 

beam elements, when energized, center the tractor within the 

hole and provide enough grip to react to the force of the 

TRACTOR TECHNOLOGY 

Selection of the tractor technology was strongly based on 

pulling capabilities, reliability track record, and how each 

design fitted the completion conditions. All of the ERWs in 

the eight well campaign that required a tractor were water 

injection wells, enabling use of a large size 4 BHA. 

The hydraulic CT tractor is made up of two shaft 

assemblies connected by a control assembly (CA). The CA 

controls the hydraulic sequence required for the generation of 

the motive force. Gripping elements are located on the shaft 

assemblies (one per side) and engage the casing inside 

diameter (ID) to react to the force generated by the tractor. 

The tractor is powered and controlled by the differential 

pressure of the fluid supplied by the surface pumps via the CT 

centerline and the wellbore annulus. The tractor may be 

turned on and off by either an internal valve located within 

the CA or externally in a separate sub, depending on the 

configuration required by the operational program, Fig. 2. 

The hydraulic tractor is 4.7” in diameter with a 0.8” ID 

through hole that will pass a maximum of 140 gpm. When 

running in hole (RIH) at a rate of 1,000 ft per hour, 12.5 gpm 

of centerline fluid is used by the tractor and diverted to the 

Fig. 2. Tractor with detailed view of gripper assembly and CA. 

Fig. 3. Expanded hydraulic tractor’s grippers. 


tractor. The result is that the gripper element will not slip 

under the maximum load of the tractor’s exertion. Retraction 

of the gripper element is accomplished with redundant fail-safe 

springs, ensuring that the elements return to their non-energized 

state in all situations when the pump pressure falls below the 

threshold value. 

The operational walking sequence is as follows: Expand the 

forward gripper; direct the cylinders to move inward toward 

the CA, thereby forcing the forward tractor downhole; 

collapse the forward gripper then expand the aft gripper; 

direct the cylinders to move outward toward the tool joints, 

again forcing the tractor downhole; and finally collapse the aft 

gripper. This cycle repeats itself, producing a walking process 

that continues until the load on the tractor is sufficient to stall 

the tractor or the pressure differential is lowered below the 

start valve pressure threshold, stopping the tractor. 

HEALTH, SAFETY AND ENVIRONMENT (HSE) 

The main concern related to the HSE aspects of the project 

involved the high concentration of H 2 S observed in the Manifa 

field, which could reach 10 wt% or 1,000 parts per million 

(ppm). During the project execution a significant number of 

personnel were expected in the area, performing tasks at 

different sites from road construction to operating the drilling 

rigs. The operator had identified areas of potential H 2 S releases 

and put in place monitoring devices at designated zones of 

maximum H 2 S concentration (10 ppm and 3 ppm zones). 

The stimulation of the water injection wells was planned with 

zero flow back strategy. No pressure bleed-off at the surface was 

allowed to take place throughout the entire operation. 

The H 2 S concern was also addressed through the use of H 2 S 

scavengers. First, several H 2 S scavengers were extensively tested 

to select the type and the concentration required to protect the 

completions and the CT pipe during the entire intervention. 

Second, the pump schedule was designed to include a large 

volume of preflush fluids containing the H 2 S scavenger. During 

the logging run, the injection of the treated water would help to 

further reduce the risk of having H 2 S at surface. 

JOB OPERATION 

The generic program for the intervention in the Manifa field 

wells could be summarized as: 

1. Rig up. 

2. Pressure test. 

3. Slick line run. 

4. Injection test (optional). 

5. CT run to perform stimulation: 

• Deployment of BHA and tractor. 

• RIH and tractor operation to reach TD. 

• Spot stimulation fluids while pull out of hole (POOH) 

in alternated stages of preflush, acid and diverter. 

• POOH and pressure retrieve BHA and tractor. 

6 SUMMER 2010 SAUDI ARAMCO JOURNAL OF TECHNOLOGY 

6. CT run with MPLT: 

• Deployment of BHA and tractor. 

• RIH and perform tractor operation to reach TD. 

• Perform logging passes. 

• POOH and pressure retrieve BHA. 

7. Slick line run with gauges. 

8. Injection test 10,000 barrels per day (bpd) at maximum 

2,200 psi for 2 days. 

9. Four days falloff test with downhole gauges in the well. 

Table 3 shows the amount of fluids used for the treatment 

in each well. 

Well 1 (Deepest Well) 

The TD of the well was 28,257 ft with 6,038 ft open hole 

completed with 7” tubing. The objective was to increase the 

injection rate of this well up to 10,000 bpm with a maximum 

pressure of 2,200 psi. Since there was no record of 

interventions in such ERWs in open hole, the operator set a 

conservative goal for the CT to reach far enough to cover 

50% of the open hole section. 

A pre-stimulation injection test was done and showed that 

the well could only take 1,750 bbl/day of water with wellhead 

pressure (WHP) reaching up to 2,200 psi. The initial 

simulation showed that without the aid of friction reducer or 

a tractor, the CT would lock-up at 16,900 ft. A first attempt 

to RIH with the tractor was aborted due to a failure with a 

release valve in the CA of the tractor. In a second run, the CT 

locked up at 22,200 ft. A pull test was performed and the 

tractor was activated observing an increase of 8,000 lbs in the 

CT weight, Figs. 4 and 5. The tractor pulled the CT without 

interruption at an average speed of 10 ft/min to reach TD at 

28,257 ft. At TD, the tractor was de-activated to reduce the 

pressure drop at the BHA and maximize the pumping rate. 

Over 1,500 bbls of acid fluid stages were then pumped and 

injected in the formation as the CT was POOH. 

After reaching the TD and completely pumping the acid 

treatment fluid, a post-injection test was done to evaluate the 

stimulation effectiveness and understand the well performance. 

Fig. 4. Simulation of CT lock-up in Well 1.

The injectivity test, which can be seen in Table 4, was 

performed at 20,000 bpd and 570 psi. This result exceeded the 

initial expectation of 10,000 bpm with maximum pressure of 

2,200 psi. A second run to TD with the MPLT was performed 

without difficulties. 

Well 2 

Well 2 was newly drilled and completed as a dual open hole 

water injection well with 7” tubing. The operation was started 

by running the slick line gauges for the pre-injection test. The 

tool tagged up at 3,100 ft on a heavy oil tar, which was found 

on the tool after retrieval. The pre-injection test was started at 

1 bpm and with a WHP of 800 psi and gradually increased to 

3.7 bpm at a pressure of 2,100 psi. The estimated lock-up 

Fig. 5. Plot of CT forces during first RIH in Well 1 up to 28,257 ft. 

depth for the CT was 16,620 ft; however, during the job CT 

lock-up took place at 18,312 ft. After the pull test, the CT 

tractor tool was activated by increasing the pumping rate to 

recommence RIH CT. The CT weight started decreasing after 

24,000 ft and it stopped at 24,521 ft (junction depth). Several 

attempts to penetrate deeper were made by reciprocating the 

CT without success. The decision was made to drop the ball 

to open the circulating sub and start the stimulation from that 

point. All, except two stages were pumped with the CT end at 

the same depth. After a soaking time of 12 hours, a batch of 

pure viscoelastic diversion acid (VDA) was pumped, expecting 

it would divert flow from the lateral, which had taken most of 

the acidizing fluids. The remaining two stages were pumped 

while POOH. 

After the CT was POOH to the surface, the BHA became 

stuck in the riser, keeping the master valve from being closed. 

Several attempts were made to free the tool, including 

pumping of friction reducer, acid and mutual solvent, as well 

as pulling and setting down weight without positive results. 

Ultimately, the well was killed and an over pull was applied, 

which resulted in getting the tool out of the well safely. 

The post injection test was performed in two stages. The 

first took two days of pumping at a stabilized rate of 7 bpm 

and 600 psi of pressure. The second stage took 4 days to 

complete, pumping at an injection rate of 14 bpm at 1,170 psi 

surface pressure. No MPLT was run in this well. 

Corrosive 

Fluid 

1 2 3 4 5 6 7 8 

TD (ft) 28,257 28,757/30,120 26,816 23,623 25,300 16,385 18,365 12,600 

Spearhead 2,100 33,585 10,290 9,900 15,177 10,332 12,054 10,878 

SXE 31,416 70,662 20,286 19,800 30,354 20,412 23,814 21,756 

(gal) 

HO Spacer 15,708 21,000 10,290 9,900 15,177 10,332 12,054 10,878 

Injectivity Tractioning Treatment 

VDA (diverter) 15,708 70,662 10,290 9,900 13,455 20,542 10,332 9,324 

Total Corrosive Mixed/Pumped 64,9321 95,909 51,156 49,500 74,163 61,618 58,254 52,836 

Friction reducer 21,000 4,000 21,000 1,052 21,000 6,300 21,000 0 

Inert 

Fluid 

Mutual Solvent Preflush 35,310 70,662 20,160 19,800 30,354 20,328 23,646 21,630 

(gal) 

Mutual Solvent Post flush 17,655 35,331 10,080 9,900 15,177 10,164 11,844 10,836 

Total Inert Mixed/Pumped 52,965 105,993 51,240 30,752 66,531 36,792 56,490 32,466 

Start (ft) 21,981 18,000 23,920 21,324 23,480 15,756 

Stim. 

Run End (Maximum Depth) 28,203 24,500 26,816 23,619 25,269 Tractor 18,361 Tractor 

Total (ft) 6,223 6,500 2,896 2,295 1,789 Required 2,605 Required 

Start (ft) 22,211 19,719 22,047 

15,522 

MPLT 

Run End (ft) 28,000 Cancelled 26,700 23,560 Not Tractor 18,250 Tractor 

Total (ft) 5,790 6,981 1,513 

Required Required 

Pre- Rate (bpm) 3.5 3.7 

Treatment Pressure (psi) 2,200 2,100 

Post- Rate (bpm) 7 7 7 7 7 7 7 

Treatment Pressure (psi) 300 700 608 300 250 280 600 

Washout at No MPLT WWT WWT 

MPLT 

No 

No 

No 

No 

2,728 Required 

Not Done Not Done Not Done Not Done Not Done Not Done 

24,500 ft CT Run tractor tractor 

Comments with Tractor performed. not not 

could not pass. used. used. 

Table 3. Main pumping statistics of the campaign 


Rate (MBPD) Presure (psi) 

Target 10 2,200 

Pre-job 1.7 2,200 

Post-job 20.5 570 

Table 4. Results of injection test in Well 1 

Other Wells 

In the other six wells, TD was reached without any problems 

and the acid fluids were placed as per the plan. Only two 

wells did not need the assistance of the CT tractor. Two 

misruns were due to the CT tractor malfunctioning, which 

were fixed promptly. Similar injection results to those in 

previous wells were observed. A pre-treatment injection test 

was not recorded in these wells to save operational time. 

In Well #8, where the CT tractor was not needed, the CT 

could not pass after 9,210 ft, presumably due to an 

obstruction or washout. After the inclusion of 16 ft of straight 

bars, the CT was able to reach TD at 12,587 ft. Table 3 

provides a summary of the main statistics in these wells. 

RESULTS 

The first eight ERWs in the Manifa field were stimulated with 

CT. The CT reached TD in all wells except one. More than 

14,000 bbls of acid fluids were injected during the campaign. 

Only one well did not need production logging data. The 

operational experience with the hydraulic tractor included 

servicing six injector wells and “walking” over 39,500 ft, the 

majority of which was open hole. Four times lock-up occurred 

while the BHA was still inside the casing, resulting in the 

tractor having to operate through the shoe, all of which were 

successful. Average speeds for each run ranged from 480 ft per 

hour - 1,000 ft per hour. Other accomplishments include 

setting a world open hole “walking” record of 5,986 ft in a 

6 1 ⁄8” open hole. 

MPLT was recorded in a total of six wells. The average 

injection performance after the treatment was 7 bpm at 700 

psi; however, there were wells with injection pressures of 250 

psi for the same rates. This represents a significant 

improvement compared to injection conditions before the 

treatment at 3.5 bpm and 2,200 psi. 

Based on the multiple RIHs, the friction coefficients in open 

hole and tubular wells observed during the interventions in 

the Manifa field are on average 30% lower than the standard 

figures in other fields in the region, therefore, eliminating the 

need for use of friction reducers. 

LESSONS LEARNED AND RECOMMENDATIONS 

The lessons learned concerning CT tractor operation include 

the following: 

1. The operational experience gained has led to several new 

product developments and procedural improvements to 

ensure more reliable operations. Tractor capability was 

increased, resulting in shorter time downhole. 

2. Improvements to the gripping elements were incorporated 

to further reduce stresses when tractoring in open hole and 

alignment features were added to further assure complete 

collapse. Refurbishment and maintenance procedures were 

adjusted according to data gathered from the many runs. 

3. The tractor on/off valve was moved to an external 

repeating circulation sub (RCS) to better diagnose the 

condition of the tractor. This new external sub now enables 

the operator through the presence or lack of a 1,000 psi 

pressure reading to determine if the tractor is in the correct 

condition. The RCS also allows the tractor to be utilized 

post-treatment. This is needed if multiple treatments are 

planned in one tractor run, again minimizing time 

downhole. 

4. The use of the friction reducer is only needed as a 

contingency. 

Recommendations for improvement include: 

1. Additional indications of tractor performance while in hole 

would help in improving operation efficiency. Downhole 

measurements of operational parameters, normally 

monitored at surface would be ideal. 

2. Use of at least 16 ft long straight bars is recommended to 

overcome open hole irregularities. 

3. A smaller diameter tractor may be necessary for smaller 

completion wells. 

CONCLUSIONS 

This experience demonstrates the feasibility of performing 

stimulation operations with CT in the Manifa field to 

achieve full zone coverage, yielding optimum water 

injection rates at the lowest development cost. With the 

average injection rate increased more than tenfold, the 

requirements to drill water injection wells were reduced 

from the original estimations. 

In spite of a limited prior field track record in open hole 

environments, the CT tractor performance was overall a 

success. Moreover, the CT tractor technology has become a 

critical enabler in the Manifa field development plan. As with 

all new technologies, the exposure to jobs has accelerated the 

learning curve facilitating the necessary improvements. 

New developments are necessary to address the challenges 

ahead and continue improving interventions in the Manifa 

field development. 

ACKNOWLEDGMENTS 

The authors thank the management of Saudi Aramco, WWT 

and Schlumberger for permission to publish and present this 

article. 


REFERENCES 

1. Moore, N.B.A., Krueger, E., Bloom, D., Mock, P.W.A. and 

Veselka, A.A.: “Delivering Perforation Strings in Extended 

Reach Wells with Coiled Tubing and Hydraulic Tractor,” 

SPE paper 94208-MS, presented at the SPE/ICoTA Coiled 

Tubing Conference and Exhibition, The Woodlands, Texas, 

April 12-13, 2005. 

2. Bawaked, W.K., Beheiri, F.I. and Saudi, M.M.: “A New 

Record of Coiled Tubing Reach in Open Hole Horizontal 

Wells Using Tractor and Friction Reducer in Saudi Arabia 

History: A Case Study,” SPE paper 117062-MS, presented 

at the SPE Saudi Arabia Young Professionals Technical 

Symposium, Dhahran, Saudi Arabia, March 29-30, 2008. 

3. Nughaimish, F.N., Hamdan, M.R. and Shobaili, Y.M.: 

“Extended Reach Drilling and Causeway Utilization in the 

Development of a Shallow Water Oil Field,” OTC paper 

20112-MS, presented at the Offshore Technology 

Conference, Houston, Texas, May 4-7, 2009. 

4. Al-Shehri, A.M., Al-Driweesh, S.M., Al Omari, M. and Al- 

Sarakbi, S.: “Application of Coiled Tubing Tractor to Acid 

Stimulate Horizontal Extended Reach Open Hole Power 

Water Injector,” SPE paper 110382-MS, presented at the 

Asia Pacific Oil and Gas Conference, Jakarta, Indonesia, 

October 30-November 1, 2007. 


BIOGRAPHIES 

Mubarak Al-Dhufairi is a Production 

Engineering Supervisor for the Manifa 

development. His experience includes 

working on several fields, including 

Safaniya, Shaybah and Berri, along 

with his experience in drilling 

engineering. 

Mubarak received his B.S. degree in Petroleum 

Engineering from King Fahd University of Petroleum and 

Minerals (KFUPM), Dhahran, Saudi Arabia. 

Saleh A. Al-Ghamdi is a Petroleum 

Engineer working in the Manifa 

Production Engineering Department. 

He joined Saudi Aramco in 2002 as a 

Production Engineer with NAPE& 

WSD, where he worked in several 

fields, including Berri, Shaybah, 

Safaniya and Marjan, before he joined the Manifa 

development team in 2008. 

Saleh received his B.S. degree in Petroleum Engineering 

from King Fahd University of Petroleum and Minerals 

(KFUPM), Dhahran, Saudi Arabia. 

Vidal Noya is a Coiled Tubing Services 

Technical Manager assigned to the 

region of Saudi Arabia, Kuwait and 

Bahrain. He has 19 years of experience 

in the oil field services. Since joining 

Schlumberger, he has worked in several 

projects related to operations and 

technology in the area of well intervention and production. 

Vidal’s experience includes assignments in South America, 

North Africa, the Middle East and Europe. 

He received his B.S. degree in Mechanical Engineering in 

1991 from the Universidad Central de Venezuela, Caracas, 

Venezuela. 

Khaled Al-Aradi is an Operation 

Engineer with Schlumberger. He is 

involved in coiled tubing and 

stimulation operations and new 

technology implementation. Khaled’s 

main interest is in exploration and 

testing applications, extended reach 

coiled tubing applications, high-pressure/high temperature 

interventions, carbonate stimulation and offshore coiled 

tubing operations. 

He received his B.S. degree in Electrical Engineering 



Samer Al-Sarakbi is a Technical 

Account Manager with Schlumberger. 

He is involved in coiled tubing and 

stimulation operations and new 

technology implementation. Samer’s 

main interest is in coiled tubing 

equipped with fiber optic cable 

applications, extended reach coiled tubing applications, 

high-pressure/high temperature interventions, carbonate 

stimulation and water shut-off. 

He received his B.S. degree in Mechanical Engineering 

from Damascus University, Damascus, Syria. 

Ahmed Al-Dossary is a Coiled Tubing 

and Stimulation Technical Manager 

with Schlumberger in Saudi Arabia. 

He is involved in coiled tubing, 

stimulation and new technology 

implementation. Ahmed’s main area of 

interest is in offshore applications, 

extended reach coiled tubing applications, high-pressure/ 

high-temperature interventions, carbonate stimulation and 

coiled tubing completions. 

He received his B.S. degree in Chemical Engineering 



Ernie Krueger began his career with 

WWT International in August 1997 

working on the newly formed coiled 

tubing tractor project with an 

emphasis on Operations. He currently 

heads the optimization effort of the 

entire field operations program with 

respect to equipment, manpower, and logistics, which will 

ensure WWT International's position at the forefront of 

coiled tubing tractor technology for years to come. Along 

with operations specialties, Ernie has coauthored four U.S. 

and international patents, three with regards to the tractor 

gripping mechanisms and one with a focus on downhole 

hydraulics for hole cleaning and tractor functionality. 

In 1997, he received his B.S. degree in Mechanical 

Engineering from the Colorado School of Mines, Golden, CO. 

Dr. Norman B. Moore has 26 years of 

experience in the oil industry 

developing downhole drilling and 

intervention tools and various types of 

subsea equipment and specialty 

tubulars. He has held positions as a 

Senior Scientist, Worldwide Technical 

Product Manager, and Vice President of Engineering at 

Christensen Diamond Products, Vetco Offshore, and 

Cameron Iron Works, respectively, before becoming 

Director of Engineering at Western Well Tool. 

Norman received his B.S. degree, M.S. degree and 

Master of Philosophy (Ph.D.) in Mechanical Engineering 

from the University of Utah, Salt Lake City, UT. 

He is the recipient of a National Science Foundation 

Fellowship. 


Next Generation Technologies for 

Underbalanced Coiled Tubing Drilling 

Authors: Shaker A. Al-Khamees, Anton V. Kozlov, Serve Frantzen, Thomas Gorges, Julio C. Guzman Munoz, Anthony A. Aduba 

and Thiago P. da Silva 

ABSTRACT 

Technology improvements are continuing to expand the 

capability of coiled tubing directional drilling (CTDD) 

worldwide. Increased CTDD activity in advanced under - 

balanced reentry applications that require precise wellbore 

(multilateral) placement and real-time monitoring of 

downhole parameters has led to the development of bottomhole 

assemblies (BHAs) with enhanced functionality. 

Saudi Aramco identified CTDD as an important technology 

for redeveloping its gas reserves and is dedicated to expanding 

the technical limits of the CTDD application. Saudi Aramco 

successfully completed its first underbalanced reentry coiled 

tubing drilling (UBCTD) pilot project and is now progressing to 

consolidate this technology in subsequent UBCTD operations. 

A great emphasis has now been placed on further improving 

UBCTD project economics through improved operational 

efficiency and the introduction of new underbalanced coiled 

tubing (CT) drilling techniques and services. 

This article provides an overview of the new rib steered 

motor (RSM) technology and its potential benefits to UBCTD. 

It details recent worldwide deployments of the rib steering 

motor technology, focusing on operations in the Kingdom of 

Saudi Arabia, which provide the perfect testing ground when 

geosteering with RSMs. Future advances using UBCTD 

geosteering technology rely on a close working relationship 

between the field operator and the service company. Successful 

application of UBCTD to a wide range of mature oil and gas 

fields will enhance access to the producing reservoir and drive 

the economic extraction of additional reserves. 

INTRODUCTION 

Even with the use of cutting-edge technology and knowledge 

application in coiled tubing directional drilling (CTDD), there 

are limitations to drilling with coiled tubing (CT), of which 

the most significant are the inability to drill a straight well 

profile and transferring adequate weight to the bit 1 . 

Through the process of miniaturization and innovation, a 

small diameter rib steered directional drilling system has been 

developed for underbalanced reentry coiled tubing drilling 

(UBCTD). The introduction of the rib steered motor (RSM) is 

aimed at overcoming inherent wellbore tortuosity characteristics 

created while using conventional oriented CTDD bottom-hole 

assemblies (BHAs). Furthermore, the RSM’s enhanced 

geosteering capabilities and reduced dogleg severity (DLS) serve 

to extend the lateral reach potential before CT lock-up. 

Rib-steering technology has been successfully tested on the 

North Slope of Alaska, in North Texas 2 and most recently on 

the UBCTD project in the Kingdom of Saudi Arabia (KSA). 

Straighter, longer horizontal laterals, and improved steering in 

borehole sizes as small as 2¾”diameter have been achieved, 

consequently improving the precision of well placement when 

geosteering within the narrowest of pay zones. 

TECHNICAL BACKGROUND 

CT material properties are such that only a small percentage 

of the drillstring weight actually gets transferred to the bit. 

Unlike conventional drilling where the drillpipe weight is 

regulated via the rig brake, CTDD requires a mechanical 

injector at the surface to push the coil in the hole to get 

adequate weight transfer to drill. Because of the mechanical 

properties of CT, as the compressive forces are increased, 

the coil buckles in a sinusoidal fashion. When the com - 

pressive forces are further increased to a critical level, the 

tubing deforms into a helical shape. Any additional force 

applied will increase the normal force of the CT against the 

wall of the well. The transferred weight to the wall of the 

hole, along with the wall friction, opposes the movement of 

the CT in the hole – a condition known as helical lock-up 3 . 

While the industry continues to explore options to improve 

the properties of the CT itself; if the friction losses 

encountered while drilling could be reduced, the weight 

would be more efficiently transferred to the bit. This 

limitation in CT drilling indicated the need for development 

of other techniques. 

Good hole cleaning procedures have been developed over 

the years to reduce friction losses. Along with improved fluids 

and wiper trip schedules, the option to continuously circulate 

even while tripping resulted in eventually overcoming part of 

the weight transfer issue. The development of tools for 

underbalanced drilling and managed pressure drilling 

techniques, along with the expertise gained with experience, 

have led to an improvement in the lateral lengths that can be 

drilled today. 


Despite these improved techniques, weight transfer in 

CTDD projects continues to be problematic. Unlike 

conventional rotary drilling, in CTDD the coil cannot be 

rotated, and therefore the drilling can only be done in sliding 

mode. Consequently, when operating in the horizontal or 

tangent section of the well, the CT undergoes constant 

orientation and tool face (TF) correction to stay close to the 

vertical section of the desired well path. TF changes lead to a 

tortuous wellbore, which increases drag and reduces weight 

transfer to the bit. By reducing the tortuous wellbore profile, 

friction losses can be reduced, which in turn improves weight 

transfer to the bit to allow drilling of longer laterals. 

Elimination of TF changes altogether, while still allowing 

operators to geosteer and navigate in the reservoir as needed, 

is required to overcome this limitation. The theory behind 

good weight transfer to the bit comes directly from 

conventional rotary drilling systems; the lateral lengths drilled 

will be longer if wellbore sections can be drilled without 

curvature. 

A RSM BHA that uses pads to push against the formation 

rock to maintain the wellbore in the desired well path — 

rather than orienting a bent motor to stay close to the desired 

vertical section — is proven technology 4 that has been 

recognized as an excellent means to reduce friction losses due 

to TF changes. The challenge was to design such a BHA and 

miniaturize it to the 3”size frequently used in CTDD 

worldwide. Additional necessities include real-time 

communication with the tool and the functional capability to 

navigate and geosteer as desired in the pay zone or fault 

blocks. The existing e-Line based system was the ideal choice 

for the implementation of rib steered technology without 

sacrificing its other valuable features, such as fast data 

transfer rates and control of direction as necessary 1 . 

The current rib steered tool design has a reduced length, 

compared with a conventional oriented bent motor coil drilling 

assembly, which places the measured while drilling (MWD) 

sensors closer to the bit, and it also has an integral near bit 

inclination (NBI) sensor to assist in geosteering. Availability of 

this technology in 3” and 2 3 ⁄8” sizes further improves extended 

reach drilling (ERD) applications using slim hole CT reentry. 

Rib Steered Technology Introduction for CTDD in North 

America 

The idea of using rib steered technology to successfully 

geosteer the well in thin pay zones while improving 

borehole quality and extending lateral reach appealed to 

CTDD operators in North America. Subsequent field tests 

of the RSM were carried out to evaluate its functionality 

and integration with existing e-Line based CTDD BHAs. 

Since its first deployment in 2007, the RSM has been 

successfully used to drill seven wells on the Alaskan North 

Slope and three wells in the Texas Panhandle as part of the 

field tests in North America. 

RSM Case History – North Slope of Alaska 

The Prudhoe Bay field is the largest oil field on Alaska’s 

North Slope. The highlighted well is located in the northern 

part of the field. The majority of Prudhoe Bay’s wells were 

drilled in the 1980s and the field is now depleted. With few 

faults the producing reservoir is, for the most part, 

homogeneous, making it ideally suited for field testing the 

prototype RSM tool. 

The original well was drilled vertically to 2,500 ft and then 

gradually built an angle to 50° at 13,000 ft measured depth 

(MD). The planned reentry involved kicking off at 12,600 ft 

and drilling a 2,400 ft lateral section to total depth (TD) at 

15,000 ft. A conventional CT drilling assembly was used in 

the build section to drill a 20°/100 ft curve. To maximize the 

lateral extension it was critical to reduce wellbore tortuosity 

and therefore minimize hole coil drag. The RSM was used to 

successfully drill the first lateral, maintaining a straight line 

trajectory in the pay zone as per its objective. The average 

DLS was reduced to 2°/100 ft, resulting in a less tortuous 

lateral section and reduced hole drag. Originally planned for 

19 days, the lateral section was drilled in six days, allowing 

for a second sidetrack to be drilled from the first lateral. Both 

laterals were drilled in one run. The first lateral leg was 2,049 

ft and the second leg was 1,417 ft in length, representing the 

longest combined lateral footage drilled with the rib steered 

assembly at the time. The success of the rib steered technology 

in improving drilling performance and extending lateral reach 

opened new reentry well candidates on the North Slope of 

Alaska with targets that could not be reached otherwise. 

RSM Case History – Texas Panhandle 

A UBCTD reentry campaign was executed to improve 

production from the tight gas reservoir and rejuvenate the 

existing basin. The existing vertical motherbores had a 5½” 

completion in place making slim hole reentry the ideal 

solution to perform a casing exit and construct a wellbore in 

the target. A high DLS of 25°/100 ft from the vertical 

motherbore was required to minimize shale exposure prior to 

target sand intersection. The build section was drilled using 

conventional drilling from the window exit in the existing 

5½” completion and isolated with a 4½” liner. The target pay 

zone was drilled underbalanced to prevent fluid losses as well 

as formation damage. CT drilling was viewed as the enabling 

technique due to its benefit of allowing pressure deployment 

and ease of operation with compressible fluids. An RSM tool 

was introduced to the project in the Fall of 2008 and was 

successfully tested on three wells. 

The first well was drilled in two days (1,562 ft lateral) 

compared with nearly four days as originally planned. Due 

to the success of the first test, the rib steered assembly was 

used to drill two more wells with lateral departures of 1,510 

ft and 1,817 ft, respectively. Rate of penetration (ROP) 

improve ment averaged 130 ft/hr, compared with 50 ft/hour 


to 60 ft/hour with the hydraulic orienting tool (HOT) 

configuration, allowing for all three wells to be completed 

two days ahead of schedule. 

KSA UBCTD Project Background 

The Ghawar field is by far the largest conventional oil field in 

the world, and accounts for more than half of the cumulative 

oil production of Saudi Arabia. Beginning in the 1980s, deep 

drilling through the Jurassic beneath Ghawar field has proved 

up large reserves of gas, sometimes with condensate in the 

Permian Khuff limestone and pre-Khuff sandstone. Now Saudi 

Aramco is developing Khuff and pre-Khuff gas beneath 

Ghawar 5 . 

In several areas around the world, including the U.A.E. 6, 7 

and North America 2, 8 , it was proved that UBCTD reentries 

can provide cost-effective access for infill drilling activity. 

Testing this technology in the Khuff limestone reservoir was a 

logical step towards further opening up those resources. In the 

summer of 2008, the first UBCTD pilot project in the 

Kingdom of Saudi Arabia was undertaken to evaluate the 

feasibility of reentering old wellbores using UBCTD to reverse 

declining gas production. 

Vertical Khuff gas producers, completed with 4½”, 5½” or 

7” liners, were reentered and sidetracked using CT. A typical 

operational sequence for the current UBCTD project includes 

running and setting a whipstock and exiting the liner by 

milling a window, sidetracking the well and drilling one lateral 

across the Khuff formation, performing open hole sidetracks 

and drilling up to three more laterals. All operations are 

typically performed underbalanced while the well is 

producing. As of October 2009, 11 wells (31 laterals) were 

successfully drilled, exposing up to 7,000 ft of open hole per 

well and averaging 1,511 ft of lateral length. 

After a nine well pilot phase was successfully completed 

using personnel and best practices from around the world, a 

great emphasis was placed on further improving UBCTD 

project economics through improved operational efficiency 

and the introduction of new underbalanced CT drilling 

techniques and services. 

As lessons were learned and office engineering personnel 

and crews on location became more experienced, the average 

number of operating days on location required to drill 500 ft 

of open hole fell from 4.2 to below three days, Fig. 1. 

New Technology Introduction to UBCTD Project in KSA 

Since its first deployment in the Middle East at the end of 

March 2009 to October 2009, a 3” RSM tool has been tested 

in six consecutive wells drilling 15,551 ft in 15 runs and 

successfully performing five open hole sidetracks. The RSM 

has contributed to achieving the following major 

improvements in drilling the lateral sections: 

• Optimization of the biosteering process together with 

the introduction of new rib steered technology helped 

maximize reservoir exposure, extending lateral reach 

Fig. 1. UBCTD project days/500 ft. 

Fig. 2. UBCTD project motor performance comparison. 

and using advanced inclination control modes to stay 

within the 2 ft porosity zones. The longest lateral on the 

current UBCTD project was drilled with the RSM tool 

never leaving the pay zone. 

• Average ROP in the pay zone was increased by 35%, 

Fig. 2, when drilling with the RSM tool BHA compared 

with a conventional oriented bent motor coil drilling 

assembly. The rib steered BHA has also set a daily 

footage record of 968 ft/24 hrs for the current UBCTD 

project. 

As an illustrative example of the advantages that rib steered 

technology brings to the UBCTD operations, three case 

scenarios were evaluated to assess the weight on bit (WOB) 

available/reachable depth: 

1. CASE 1 - Planned Well Path – AKO 0.8: Using oriented 

bent motor, which requires constant orientation and TF 

corrections generating an anticipated DLS of 7°/100 ft. 

2. CASE 2 - Planned Well Path - RSM: Using rib steered 

technology, which requires a straight well profile with 

anticipated DLS of 0-1°/100 ft. 


3. CASE 3 - Actual Well Path RSM: Drilled on one of the 

wells on the current UBCTD project using rib steered 

technology to TD at 14,215 ft MD. 

Figures 3 to 6 show graphically the difference between the 

three cases above for the same well and illustrates how well 

path undulation and tortuosity affects available WOB for 

CTDD applications. Inclination (deg) and DLS (deg/100 ft) 

are plotted in Figs. 3 to 5 as a function of MD. Figure 6 

shows maximum available WOB for each case and is also 

plotted as a function of MD. 

Computer aided simulation has been used and proven the 

value of using RSM technology. The Tubing Forces 

Simulations Results (Torque & Drag) were then generated 

considering identical assumptions, where only the well path 

was a variable for the three case studies. 

Fig. 3. CASE 1 - Well profile survey severity planned well path with oriented 

bent motor. 

Fig. 4. CASE 2 - Well profile survey severity planned well path with RSM. 

Fig. 6. Maximum available WOB. 

As shown in Fig. 6, using rib steered technology adds a 

significant advantage to the drilling of the laterals: While in 

CASE 1 the maximum WOB achievable before lock-up is 925 

lbf, the same planned lateral – CASE 2 using the RSM – has a 

maximum available WOB of 2,640 lbf at the same MD of the 

planned well. An increase of 185% of available weight was 

transferred to the bit merely due to reduced well path 

tortuosity. The actual well path drilled with RSM – CASE 3 – 

has the available and measured WOB at TD in the range of 

1,990 lbf at TD. This is 25% lower than expected of RSM 

performance, but 115% higher than when using an oriented 

bent motor. 

Similarly, maximum available pickup weights on the BHA 

at TD increase substantially when using the RSM BHA. The 

use of rib steered technology allowed for roughly an 87% 

higher additional pickup off bottom when comparing CASE 1 

vs. CASE 2. Maximum Allowable Pull for the three cases 

discussed was 6,780 lbf, 19,520 lbf and 13,150 lbf, 

respectively. 

Transcripting the results of available WOB into increased 

reach, the analysis shows that the well path in CASE 2 can be 

extrapolated to the depth of approximately 16,250 ft MD 

(additional 2,035 ft) while the actual results of the per - 

formance of RSM while drilling show that the actual leg could 

have been drilled up to 15,300 ft MD, if requested. TD on the 

actual leg was called due to reasons other than running out of 

available WOB. 

The results above not only demonstrate that wells drilled 

using the RSM, which reproduces a well path with low 

tortuosity, will be a lower risk from the surface/downhole 

weights point of view, but they can be traded off by extended 

reach possibilities, enhancing even more of the future of 

CTDD applications. 

CONCLUSION 

Fig. 5. CASE 3 - Well profile survey severity actual well path drilled with RSM. 

Since the first introduction of rib steered technology to the 

field in 2006, the RSM tool, throughout its field test campaign 

has successfully proven its value to the CTDD and UBCTD 

operations by constantly increasing lateral reach and 


improving drilling performance. The RSM extended reach 

capabilities combined with advanced geosteering capabilities 

helped improve the ongoing UBCTD project and made it the 

technology of choice for drilling the lateral sections going 

forward. 


The authors wish to thank Saudi Aramco management for 

their support and permission to present the information 

contained in this article. 

REFERENCES 

1. Madarapu, R., Lasley, B.M., Corson, C.S., Hinze, I. and 

Carey, S.: “Advances in Coiled Tubing Reentry Access 

Bypassed Reserves on Alaska's North Slope,” SPE paper 

107665, presented at the SPE Latin American and 

Caribbean Petroleum Engineering Conference, Buenos 

Aires, Argentina, April 15-18, 2007. 

2. Denton, S., Dietrich, E., Ortiz, R., Cadena, J. and 

Ohanian, M.: “Cleveland Tight Gas: CTD/MPD Reentry 

Campaign Results,” SPE paper 120846-PP, presented at the 

SPE/ICoTA Coiled Tubing and Well Intervention Con - 

ference and Exhibition, The Woodlands, Texas, March 31 - 

April 1, 2009. 

3. Goodrich, G.T., Smith, B.E. and Larson, E.B.: “Coiled 

Tubing Drilling Practices at Prudhoe Bay,” SPE paper 

35128, presented at the SPE/IADC Drilling Conference, 

New Orleans, Louisiana, March 12-15, 1996. 

4. Janwadkar, S., Fortenberry, D., Dawkins, B., Kramer, M., 

Privott, S. and Rogers, T.: “Innovative Advanced 

Technologies Overcome Directional Drilling Challenges of 

S and J Type Wells in N. America and Canada,” SPE paper 

102028, presented at the SPE/IADC Indian Drilling 

Technology Conference and Exhibition, Mumbai, India, 

October 16-18, 2006. 

5. Entrepreneur: “Saudi Arabia - The Arab Light Producers - 

Ghawar Group,” www.entrepreneur.com. 

6. Johnson, M., Brand, P., French, S., et al.: “Coiled Tubing 

Underbalanced Drilling Applications in the Lisburne Field, 

Alaska,” IADC/SPE paper 108337, presented at the 

IADC/SPE MPD/UBD conference in Galveston, Texas, 

March 28-29, 2007. 

7. da Silva, T.P., Kavanagh, T., Rennox, J., Savage, P. and 

Capps, J.: “A Process Delivery Template for an 

Underbalanced Coiled Tubing Drilling Project from 

Concept to Execution,” SPE paper 107244, prepared for 

the SPE/ICOTA Conference, The Woodlands, Texas, March 

20-21, 2007. 

8. Suryanarayana, P.V., Smith, B., Hasan, A., Leslie, C., 

Buchanan, R. and Pruitt, R.: “Basis of Design for Coiled 

Tubing Underbalanced Through-Tubing Drilling in the 

Sajaa Field,” IADC/SPE paper 87146, prepared for the 

IADC/SPE Drilling Conference, Dallas, Texas, March 2-4, 

2004. 


BIOGRAPHIES 

Shaker A. Al-Khamees is a Senior 

Drilling Superintendent at the Gas 

Development Drilling and Workover 

Department, Saudi Aramco. His areas 

of interest include advanced drilling 

techniques, multistage completions, 

workover and snubbing operations, and 

he is currently involved in leading several vital projects in the 

area of underbalanced coil tubing drilling, conventional 

underbalanced drilling and deep gas workover operations. 

Shaker received his B.S. degree in Petroleum 

Engineering from the University of Southwestern 

Louisiana, Lafayette, LA. 

During his 25 year career, he has presented and 

published many technical papers. Shaker is a member of 

the Society of Petroleum Engineers (SPE). 

Anton V. Kozlov started his career as a 

MWD/LWD Engineer working for 

Baker Hughes in Western Siberia, 

Russia. He has been involved with 

coiled tubing drilling for the last 2½ 

years, first as a Field Test Engineer 

working in Texas and Alaska, and for 

the last year as a Coiled Tubing Drilling Applications 

Engineer based in al-Khobar, Saudi Arabia. 

In 2006, Antov received his B.S. degree in Petroleum 

Engineering from the Gubkin Russian State University of 

Oil and Gas, Moscow, Russia. 

Serve Frantzen is currently employed 

with Baker Hughes as a CTD Project 

Coordinator and is working with the 

Saudi Aramco CTD project team. 

Previously, he was part of the CTD 

project teams in Sharjah and 

Margham, U.A.E. and Alaska, U.S. 

Serve began his career in the oil and gas industry in 1988 

and was involved in major drilling projects like the first six 

well jointed pipe UBD project in Europe in 1994/95 for 

RWE-DEA in Breitbrunn, Bavaria, Germany. Besides the oil 

and gas industry he was also involved in major drilling 

projects for the pipeline and mining industry. 

Thomas Gorges joined Baker Hughes 

in November 2006 as a Drilling 

Applications Engineer for Reentry 

Systems, which incorporates coil 

tubing and through tubing rotary 

drilling. As an Applications Engineer, 

he has been involved with the technical 

transfer of new products to the field and marketing of CTD 

services. Participating in conventions and forums is a 

crucial part of his work, and Thomas has authored and 

contributed to several coiled tubing related papers. 

Thomas graduated from the University of Applied 

Sciences in Wolfenbuettel, Germany, with a Diplom – 

Ingenieur in Mechanical Engineering. 

Julio C. Guzman Munoz is a Drilling 

Engineering Supervisor at the Gas 

Development Drilling & Workover 

Department, Saudi Aramco. During his 

13 year career in the oil and gas 

industry, he has been associated with 

coiled tubing drilling, multilateral and 

extended reach drilling, batch drilling and deep gas drilling 

in Colombia, Venezuela, the United States, Mexico and 

Saudi Arabia. Currently, Julio is providing the engineering 

support for several key initiatives for Saudi Aramco 

Drilling & Workover, including coiled tubing drilling, 

underbalanced drilling, innovative cementing design and 

drilling fluids management. 

Julio received his B.S. degree in Petroleum Engineering 

from the Universidad Industrial de Santander, 

Bucaramanga, Santander, Colombia, in 1997. 

Anthony A. Aduba previously worked 

as a Drilling Supervisor, Drilling 

Engineer and Petroleum Economist 

with Shell from 1996 to 2008, before 

joining Saudi Aramco as a Drilling 

Engineer in the Gas Development 

Drilling & Workover Department. He 

was assigned to the Underbalanced Coiled Tubing Drilling 

project in March 2009. 

In 1992, Aduba received his B.S. degree in Chemical 

Engineering from Enugu State University of Science and 

Technology, Enugu, Nigeria. In 1995, he received his M.S. 

degree in Chemical Engineering from the University of 

Lagos, Lagos, Nigeria. 

Thiago P. da Silva is currently a 

Schlumberger Project Engineer for 

Saudi Aramco’s Underbalanced Coiled 

Tubing Drilling (UBCTD) project. His 

previous experience in UBCTD 

campaigns includes BP Sharjah Oil 

Company and Margham Dubai 

Establishment. 

Thiago has received several industry awards, including 

the Halliburton Recognition Plaque awarded from the 

Carrollton Technical Paper Review Board, a Certificate of 

Appreciation from Margham Dubai Establishment, and an 

Appreciation Award from the BP Sharjah UBCTD project. 

He has also been a guest Instructor at the Brazilian 

National Petroleum Agency. 

Thiago received his B.S. degree in Mechanical 

Engineering from the Universidade Federal de Itajuba, 

Minas Gerais, Brazil, in 2003. 


Robotics for Horizontal Image Acquisition in 

Ultra Slim Wells in Saudi Arabia 

Authors: Kanwal B. Singh Khalsa, Nassar A. Al-Awami, Nelson Pinero, Zaki A. Al-Baggal, Adib A. Al-Mumen 

and Ibrahim A. Zainaddin 

ABSTRACT 

The cost savings that are possible by sidetracking existing 

wellbores make the drilling and completion of ultra slim 

lateral wells very desirable. Obtaining image logs from 

horizontal wells, less than 6” diameter, has always been a 

challenge, because the size of conventional borehole imaging 

tools that currently exist on the market are simply too large. 

In addition, conventional deployment methods limit efficient 

rig time utilization and ultimately lead to higher cost. New 

conveyance and logging technology from Welltec ® (the Well 

Tractor ® ) and Weatherford (The Compact Micro Imager 

(CMI)) allows operators to obtain excellent image logs in slim 

wells as small as 3” in diameter. Image logs are required to 

properly understand fracture details and to help in future 

drilling and completion decisions. 

This article describes the logging operational experience of 

the CMI and the world’s first slim hole imaging logs in Saudi 

Arabia deployed by the wireline tractor 218XR (XR: 

Extended Reach) in an open hole horizontal section. 

INTRODUCTION 

Workover operations are a major part of any oil field 

operation. Well maintenance and repair are performed during 

workover operations. Repairs include replacement of 

completion string, casing patch, perforation shut-off, etc. In 

addition, reentry and horizontal drilling and open hole 

completion technology has enabled the operators to increase 

production and recovery rates from declining fields and short 

interval pay zones. 

ABQAIQ FIELD 

Initially, the field was developed by drilling vertical producers. 

The remaining oil column is short and can go as low as 3 ft to 

4 ft in some areas. With the field in production, water cut has 

increased with time. One strategy to save the cost of drilling 

new wells is to re-visit old vertical wells and complete them as 

horizontal producers. 

The reentry horizontal drilling methodology for Abqaiq 

field has evolved over time. Due to the original 7” cased hole 

production completion, a 6 1 ⁄8” window is cut for sidetrack in 

the 7” casing and the curve section is drilled to above target 

formation, and a 4 1 ⁄2” or 5” liner is run to isolate the highpressure 

water formation just above the pay formation. After 

casing off the curve section, drilling proceeds with either a 

3 7 ⁄8” or 4 1 ⁄8” horizontal hole in the target formation until 

reaching total depth (TD). 

The wells are normally completed with Inflow Control 

Devices (ICDs) and open hole mechanical/swell packers. The 

ICD completion uniformly distributes production across the 

entire horizontal section, and delays water and gas coning, 

therefore extending well life and maximizing oil recovery. 

Another issue with such wells are the fractures encountered 

during drilling. The drilling mud gets absorbed by fractures 

due to lower pressure. At this stage, to identify the fracture 

zone, wireline image tools need to be deployed horizontally in 

the open hole, to determine length and width of the fracture. 

Running the image log would also facilitate the design of the 

open hole completion with ICD and packers to provide a 

barrier or isolation between normal production zones and the 

fractured zone. 

Abqaiq wells A and B were sidetracked with 3 7 ⁄8” and 4 1 ⁄8” 

holes, respectively, during the last workover. Both wells had 

high water cut and low-pressure where they could not flow to 

the Gas-Oil Separation Plant (GOSP). It was believed that if 

the fractures (encountered during sidetracking) could be 

isolated and production could be distributed over the length 

of the lateral with ICD systems, the water breakthrough 

would be delayed. 

INTERVENTION STRATEGY 

Sidetracking into the targeted formation horizontally requires 

extensive engineering in both the planning and execution 

phase, so as not to damage the slim hole (3 7 ⁄8” and 4 1 ⁄8” bit 

size). Once the sidetrack is drilled and further trips are 

required with drillpipe for logging purposes, that were often 

not in the original plan, the risk of hole damage increases. 

Wells with these slim holes and sidetrack geometry often 

provide additional challenges in respect to dogleg severity 

(DLS) and drillpipe sticking. Risks are also increased on the 

logging tools as the compressive strength of such sensitive 

tools are no match for the drillpipe strength. 

Time efficiency for completing these wells, which needed 

mitigation, requires fast intervention decisions by the operator. 


The choice of tractoring in such slim holes with fragile tools 

provides the best choice with respect to the speed of operations, 

and risks taken on sight or inside the borehole. Tractors provide 

the means for real time log quality control (LQC) and also 

wireline depth accuracy. In addition, well tractor technology has 

enabled increased well intervention capacity for operators by 

providing alternatives to pipe conveyance or pump-down when 

other services are required, such as gyro’s, vertical seismic profile 

(VSP), pressure or fluid sampling, etc., which may not be 

suitable owing to either the extended operational time involved 

or to the potential risk of formation damage. 

In this particular operation, water breakthrough had been 

encountered and a wireline logging job was required to 

identify the water entry point for proper remedy planning and 

installation of ICD systems at that depth during the well recompletion 

phase. A decision was made to recomplete the well 

with an ultra slim hole passive ICD system. To do that 

correctly, a high resolution resistivity image log was required. 

Statement of Theory and Definition 

There are several benefits to well tractor operations but the 

two most important in the slim hole logging domain are the 

health, safety and environment (HSE) and service quality. 

Health, Safety and Environment 

Lighter equipment, less lifts with heavy load, and less time 

with less people performing the job, results in less risk to 

personnel in the field. The time efficient operation and small 

footprint result in less impact on the environment. 

SERVICE QUALITY 

The cost savings have been achieved due to the increase in 

operational efficiency and well optimizations as more types 

of interventions can be performed more often in less time 

without the need of workover rig mobilization. Conventional 

deployment methods only offer memory mode logging with 

image tools. By utilizing a wireline tractor, the wireline cable 

is used to deploy and to send/receive data to and from the 

acquisition system at surface real time. The flexibility of this 

image tool design enables it to operate as a depth based tool 

for quality control while logging as opposed to memory 

mode logging. 

A tractor deployed tool string will have the flexibility to 

run in hole (RIH) and pull out of hole (POOH) with wireline 

speeds up from the surface to the hang up depth (approx. 65 

degrees). Tractor speeds averaged over 1,100 ft/hr for the 

3 7 ⁄8” and over 1,600 ft/hr for the 4 1 ⁄8” size hole at the 

horizontal section. The performance translates into better 

time utilization of the rig. Another advantage is real time 

LQC of data and better vertical resolution. The need to 

coordinate between drillpipe speed and wireline cable POOH 

speed eliminated the data drop from fast speeds. Also, the 

risk of the cable being cut, due to drillpipe is eliminated as 

well. The real time LQC gives the client the ability to plan 

for the well completion and ICDs or packers while the job is 

proceeding. Image tools require a steady POOH speed to 

provide the higher vertical resolution with no drop in data, 

due to an increased speed of the tool or sticking in the hole. 

THE IMAGE TOOL 

The image tool weighs 126 lbs, and is 18.04 ft in length. It 

consists of eight arms with eight buttons per pad. The sample 

rate (depth) is one sample per 2 mm of depth. Its vertical 

resolution is 5 mm. High resolution time based data can be 

retrieved at surface via a USB upload to a PC for speed 

correction (Memory) and time to depth conversion (Real Time 

LQC). The image tool can be configured to be either 4.1” 

outside diameter (OD) or 2.4” OD, by interchanging the pads. 

This allows operators to acquire resistivity images in wells 

with hole sizes ranging from 3” to 12 1 ⁄4”, which is within the 

range of the wells considered. 

Abqaiq Well A 

This well was drilled and completed in 1977 as a vertical open 

hole oil producer. It was drilled as an 8 1 ⁄2” hole and a 7” liner 

was set. The reservoir was drilled with 100% circulation. 

Several workovers have been performed to replace tubing, 

perform preventive maintenance, check casing corrosion, run 

4 1 ⁄2” tubing and deepen the well. 

In 2002, the well was plugged back to isolate the bottom 

part of the perforation and capped with 5 ft of cement to 

evaluate the production potential of part of the formation. 

The well did not flow to the GOSP. 

In 2005, another workover was carried out to sidetrack 

and drill a 3 7 ⁄8” open hole to a TD of 10,200 ft. While drilling 

the open hole, there was a complete loss of circulation at 

8,363 ft, but drilling was continued to TD with water/gel 

sweeps and a mud cap. Open hole logs recorded resistivity, 

neutron, density and gamma rays, and were acquired on the 

drillpipe. The well was completed with 4 1 ⁄2” tubing. 

The well could not flow to the GOSP after the workover 

despite several attempts to revive the well. 

Abqaiq Well B 

Abqaiq well B was drilled and completed in 1991 as a vertical 

open hole oil producer. The 6” vertical hole was drilled to a 

TD at 6,298 ft with 100% circulation. The well was 

completed with 4 1 ⁄2” tubing. 

The well was reclassified as a wet producer in 1992. Water 

cut increased with time, and in 1998 it was found that the 

well could not flow to the GOSP at normal operating 

pressure. It was flowed at reduced GOSP pressure, tested, and 

a 72% water cut was found. 

Workover was carried out in 2005 to plug the existing open 

hole, to sidetrack and to drill a 4 1 ⁄8” lateral section. The 4 1 ⁄8” 

hole was drilled until complete loss of circulation was 

encountered at 7,915 ft, but then drilled ahead with water and 


mud cap to TD at 10,100 ft. Open hole logs recorded 

resistivity, neutron, density and gamma rays and were 

acquired on the drillpipe. The well was completed with 4 1 ⁄2” x 

2 7 ⁄8” tubing, subsequently tested, and found to be dead. 

DESCRIPTION AND APPLICATION OF EQUIPMENT 

AND PROCESSES 

218 Well Tractor 

The wireline tractor is a wireline deployed, self-propelled 

robotic device that pushes wireline tool strings out to the end 

of the wellbore. When the tractor is activated, the wheels 

come out of the tool body by overcoming the built-in springs 

that keep the wheels inside the body. The wheels also 

centralize the tractor in the wellbore by distributing the force 

of the wheel arms around the wellbore. Once the wheels 

establish contact with the casing or open hole, the wireline 

tractor starts to move forward and deploys the logging tools 

into the horizontal wellbore, taking the string beyond the 

original hang up point (usually between 60 to 65 degrees for 

wireline cable). Once the tool string reaches its objective 

depth, the wireline tractor is powered down, retracting the 

wheels inside the tool body. It now resembles a passive 

through wired tool so the wireline tool string can start 

logging, and be pulled out of the wellbore. If extra survey 

intervals are required, the tractor can simply be operated 

again and run to the required depth. This set up also enables 

logging while tractoring. The tractors can handle perforating, 

cement bond logging, production logging, run open hole logs 

and enable coiled tubing (CT) to reach beyond the friction 

buckle point (i.e., maximum depth the CT can go before 

stopping, due to buckling and friction). 

The standard wireline well tractor consists of the following 

sections, Fig. 1: 

• The top connector provides the mechanical and 

electrical connection between the cable head and the 

tractor. 

• The electronics section provides control and power. 

• The motor section powers the hydraulic pump section, 

which in turn extends and retracts the wheels and 

rotates the wheels for forward movement of the tractor. 

• Wheel sections - The tractor can have up to five wheel 

sections. The configuration is decided depending on 

hole size, DLS, power and speed requirements. Each 

wheel section is phased (rotated) 90 degrees in relation 

to the adjacent section. Every wheel section has an 

integrated two wheels to propel the tractor, Fig. 2. 

• Compensator - Equalize pressure between downhole 

hydrostatic pressure and inside housing tool pressure. 

• The bottom connector provides the mechanical and 

electrical connection to the tools (if any) below the tractor. 

The hydraulic pump section provides hydraulic pressure in 

the tractor and is used to extend and retract the spring loaded 

wheels, and to provide normal force against the well tubing or 

Fig. 1. Example of wireline Well Tractor 218 configuration (Shown with a three wheel section). 

Fig. 2. Normal force and torque. 


open hole. This operation centralizes the tractor in the hole. 

Also, the hydraulic system rotates the wheels and moves the 

tractor. Once power to the tractor is switched off, the wheels 

will automatically retract, making the tractor fail-safe. 

Job Planning 

WellSim is a simulation program developed especially for 

analyzing and planning wireline tractor operations. The 

simulation predicts at what depth the wireline tractor needs to 

be started, and what pull is required to get to any given depth 

in a well. The pickup weight is calculated along with a 

recommended weak point. The directional properties of the 

well, inclination, azimuth and doglegs are taken into account 

along with restrictions and casing/hole conditions, friction, 

when calculating the tool string and cable drag, Fig. 3. 

Considering the factors – cable type and weight – tool 

length and weight, the software calculates the force for the 

tractor to achieve the desired TD. The simulation program 

also recommends the proper weak point for the operation in 

case of a stuck tool. The required pull to achieve TD for the 

tractor was approximately 500 lbs of force. 

A surface pull test of tractors, after major maintenance, is 

favorable to have a surface indication of the actual tractor 

pull. An average of over 1,000 lbs on surface has been 

achieved with a four wheel section 2 1 ⁄8” OD tractor. This is 

two times the required force to achieve TD, as per the 

software calculation. 

A surface power up and tool surface check is necessary 

prior to deployment to any job. This ensures foreseeing any 

issues that might appear on the well site with respect to power 

requirements and telemetry communication. Full surface tests 

and operational checks were performed with the image tool to 

ensure switching operations between powering and running 

the well tractor and image tool link up and logging mode. 

Presentation of Data and Results 

The wireline tractor, in combination with the image tool, has 

been tested and deployed two times successfully at both 

Fig. 3. Software output. 

Abqaiq wells with a downhole environment of 3,500 psi 

pressure and 213 °F temperature (Tractor Rating: 24 kpsi 

psi/400 °F). Tractoring speed was 27.5 ft/min (1,650 ft/hr) 

and 19.5 ft/min (1,170 ft/hr), respectively, with > 1,000 lb 

cable tension recorded (wireline tractor test: 2,400 ft/hr at 800 

lbs up to 4,000 ft/hr at 600 lbs). The wireline tractor was 

configured with four wheel sections yielding a length of 21.4 

ft and has been able to negotiate obstructions and DLSs of up 

to 13.35 degrees in open hole at the Abqaiq field (Standard 

wheel sections: three wheels at 17.5 ft length; maximum DSL 

tested to 32°/100 ft at 4” inside diameter (ID)). 

The additional wheel section increases the pulling capacity 

of the tractor downhole, although it adds length to the overall 

tractor. Another advantage of the additional wheel section is 

the added benefit of negotiating long washouts. 

Well Parameters 

ABQQ-A ABQQ-B 

Date Jan. 2009 Feb. 2009 

Max. Pressure 3,500 psi 2,942 psi 

Max. Temperature 210 °F 213 °F 

Avg. Tractor Speed 1,650 ft/hr 1,170 ft/hr 

Wheel Sections 4 wheel sections 4 wheel sections 

Single/Tandem Conf. Single Single 

TD 10,200 ft 10,100 ft 

Reach 8,400 ft (82%) 10,100 ft (100%) 

Hole Size 3 7 ⁄8” 4 1 ⁄8” 

The final wireline tractor OD was 2½”, including with the 

wear rings installed. The maximum opening of the wheels for 

this setup used was 8.7” (maximum reach of 9.2” can be 

achieved with larger OD wheels). 

Job Execution and Achievement 

Real time LQC offers immediate reaction to alter the sequence 

of operations and the ability to make informed decisions. A 

second RIH during one of the jobs was performed, due to 

insufficient data acquired from the first pass with the logging 

tools. The wireline tractor successfully deployed the image 

tools in the open hole twice consecutively, with an average 

speed of 15.9 ft/min (954 ft/hr) and 19.5 ft/min (1,170 ft/hr), 

respectively, with cable tension of >1,000 lbs on both runs. 

The normal procedure of re-filling compensated oil to the 

wireline tractors was subsequently sufficient to perform 

additional runs in hole. Tractor deployment is much more 

efficient than drillpipe when considering the time to complete 

the operation on the rig. 

This operational deviation made it possible to perform the 

job in less than 24 hours from start to finish (including both 

runs and the wait on data processing). If the operation had 

been executed with drillpipe or CT for logging in memory 

mode, the main and recovery operations would have taken 46 

hours from start to finish. Due to the efficient utilization of 

the rig, the operating time was reduced by 48%, compared to 


unning the operations by conventional methods. Figure 4 

shows a comparison of job cumulative time compared to a 

theoretical drillpipe conveyance speed. 

The experience acquired in this field from the two jobs has 

helped to plan for future jobs. The biggest challenge to 

overcome in slim hole size is the dogleg. Hole ovality and 

washouts are concerns second to that of the dogleg. Depending 

on the tool to be tractored, the length of tractor needs to be 

optimized for power, speed and also passing such a slim hole 

with high DLS and a change in azimuth of the hole. 

CONCLUSIONS 

Clear reduction of rig time was realized from using a wireline 

tractor over drillpipe conveyed logging. The time reduced 

resulted from improved rig time utilization, less personnel 

involved, reduced risks and hazards associated with the 

operations. Quick data turnaround enabled the operator to 

decide the completion type in much less time than was 

previously done, and to plan ahead for rig operations. 

The client had signed a performance record and 

commented the following: “[The tractor operation] ... is a 

successful alternative in slim open hole deployment for 

wireline logging tools and results in more time savings than 

conventional drillpipe deployment, and also enables rigless 

operations. Applications range from delicate slim open hole 

conditions (3 7 ⁄8” and 4 1 ⁄8” size) for deployment to larger bit 

sizes in cased hole or open hole conditions. Risks are 

mitigated on both the wireline tools being deployed and 

wireline cable vs. conventional drillpipe deployment.” 


Fig. 4. Timing comparison Tractor vs. Drillpipe. 

The authors wish to thank Saudi Aramco, Welltec and 

Weatherford management for their support and permission to 

present the information contained in this article. 


BIOGRAPHIES 

Kanwal B. Singh Khalsa joined the 

company as a Workover Engineer in 

February 2007, and is involved in the 

planning and execution of sidetracks, 

mechanical workovers and safety 

workover jobs. Prior to this, he 

worked for ONGC, India, from 1991- 

2004 in Mumbai as a Workover Engineer/Supervisor in the 

offshore rigs. From 2004-2007, Kanwal worked onshore in 

the Western region (Gujarat) in India as a Workover 

Supervisor. 

In 1990, he received his B.S. degree in Mechanical 

Engineering from the Government Engineering College, 

Raipur, India. 

Nassar A. Al-Awami is the Operations 

Manager at Welltec in Saudi Arabia, 

responsible for the implementation of 

Well Tractor services. He began his 

career in 2001, working briefly for 

Unilever before moving on to work for 

Schlumberger as a Seismic Engineer, 

eventually becoming the Wireline Cased Hole Field Services 

Manager. During his 7 years with Schlumberger, Nassar 

worked throughout the Gulf area region and Southeast 

Asia. 

He received his B.S. degree in Applied Electrical 


Minerals (KFUPM), Dhahran, Saudi Arabia, in 2001. 

Nelson Pinero began his career in 

1996 when he went to work for 

Lagoven, a Venezuelan oil company, as 

a Foreman. In 1997, he began 

specializing as a Drilling Engineer and 

then began working as a Drilling 

Workover Engineer. In 2003, Nelson 

started working as a Foreman in Servicios Ojeda in the 

western part of Venezuela. Two years later, he went to 

work for BP Venezuela as a Foreman. The following year, 

BP relocated him to Bogota, Colombia, to work as a 

Workover Engineer. Nelson joined Saudi Aramco’s 

Workover Department as a Workover Engineer in 2007. 

In 1995, he received his B.S. degree Mechanical 

Engineering from the National Experimental Polytech 

University, Barquisimeto, Lara State, Venezuela. 

Zaki A. Al-Baggal is currently the 

General Supervisor of the Offshore 

Drilling Engineering Division of the 

Offshore Drilling Department. He 

joined the company in 1982 and has 

held various supervisory positions in 

the Drilling & Workover organization. 

Zaki’s expertise includes deep gas and oil drilling and 

workover. 

He received his B.S. degree in Petroleum Engineering 


(KFUPM), Dhahran, Saudi Arabia, in 1982. 

Zaki is a member of the Society of Petroleum Engineers 

(SPE). 

Adib A. Al-Mumen is currently the 

General Supervisor of the Technical 

Support Services Division of the 

Drilling Technical Department. He 

joined Saudi Aramco in 1991 and has 

held various supervisory positions in 

the Drilling & Workover organization. 

Adib’s expertise includes workover optimization, complex 

wells, short radius reentry sidetracks and well integrity 

management. 

He received both his B.S. degree and M.S. degree in 

Petroleum Engineering from King Fahd University of 

Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. 

Adib is a member of the Society of Petroleum Engineers 

(SPE). 

Ibrahim A. Zainaddin is the 

Weatherford Wireline Operation 

Manager for Saudi Arabia, Bahrain 

and Kuwait. He has been located in al- 

Khobar, Saudi Arabia, for the past 3 

years in his current role. 

In 2006, Ibrahim joined 

Weatherford Wireline as the Wireline Project Manager, 

working in technical sales and sales management. He 

played a key role in the introduction of the compact 

technology in Saudi Arabia. Ibrahim has over 14 years of 

engineering experience working for several multinational 

companies. 

In 1994, he received his B.S. degree in Applied Electrical 




Stimulating Khuff Gas Wells with Smart 

Fluid Placement 

Authors: Francisco O. Garzon, J.Ricardo Amorocho, Moataz M. Al-Harbi, Nayef S. Al-Shammari, Azmi A. Al-Ruwaished, 

Mohammed Ayub, Wassim Kharrat, Vsevolod Burgrov, Jan Jacobson, George Brown and Vidal Noya 

ABSTRACT 

The objective of many matrix acidizing treatments in the 

Khuff carbonate formations is to remove drilling damage and 

enhance productivity after the drilling process. Open hole and 

multilateral completed wells present several challenges that 

prevent an optimum intervention with coiled tubing (CT). 

Traditional practices have been limited to spot stages of 

preflushes, acid, and diversion systems in front of the 

formation from toe to heel without proper control over the 

placement process. 

Using an innovative workflow, interpretation of distributed 

temperature survey (DTS) responses, correlated with reservoir 

data, assists in selectively placing fluids, and maximizing the 

contact of stimulation fluids with the targeted formation 

sections. Two field applications, in dual lateral horizontal 

open hole gas producers, that demonstrate how to optimize a 

stimulation treatment as it occurs, were implemented in a field 

in the Kingdom of Saudi Arabia. 

In both cases, selective access to pay zones in each lateral 

was confirmed with DTS profiles. Following the preflush and 

the first acid pass, DTS measurements indicated acid effect 

over the permeable zones but also detected fluid movement 

towards non-gas bearing thief zones. Foam and energized 

viscoelastic diverting acid fluids were used to divert acid to the 

target zones, avoiding the loss of all stimulation fluids to the 

toe in one case and to the heel in the other well. After 

treatment, the gas production increased from zero to more 

than two times the expected rate in both wells. 

Understanding of the flow patterns as fluids are placed in 

the wellbore was possible. Changes to the fluid placement 

schedule during the job resulted in optimum acid coverage 

and efficient diversion, confirmed by the downhole 

measurements. The identification of the thief zones was 

critical to avoid wasting fluids. This experience with the first 

ever gas wells in the Middle East, represents an opportunity 

for unlocking production potential in similar gas developments. 

INTRODUCTION 

The increasing domestic demand for gas in the Kingdom of 

Saudi Arabia is triggering more gas development projects. 

Challenging targets are set to increase the gas production in 

the coming years. Many rigs are being shifted from oil to gas 

developments. As a consequence, existing projects are under 

high-pressure to maximize the production of each gas well at 

the lowest operational cost possible, complying, of course, 

with the highest industry EHS standards. 

A significant portion of the gas production is coming from 

the South Ghawar field developments. In this area, most wells 

are completed as horizontal or highly deviated wells, and it is 

common to find dual lateral and open hole completions, 

leveraging on the consolidated carbonate Khuff formations. 

Open hole completions offer the advantage of drilling wells 

with lower capital expenditure, as tubular and associated 

completion operations, like cementing and perforating, are not 

required. In addition, the wellbore in a barefoot condition, 

contrary to a cased and perforated completion, enables better 

productivity out of the formation due to a lower skin. 

After the drilling process is concluded, the well is delivered to 

the production team. The well is flowed back for cleanup and if 

the flow performance is poor and productivity below expecta - 

tions, an intervention with coiled tubing (CT) is scheduled to 

perform a stimulation of the motherbore and lateral. 

CT is the preferred method of conveyance of fluids to 

remove the damage and perform the acid stimulation in this 

kind of completion. The first challenge in this scenario is to 

access the laterals, and second, optimizing the performance of 

the fluids spotted with the CT. 

In regards to the accessibility, it is critical to have a reliable 

technique to selectively enter into the targeted branch. Once in 

the lateral, confirmation of having entered the targeted branch 

is needed before commencing the fluid placement. This is 

normally done by tagging the end of the lateral to confirm 

total depth (TD) matching, which is time consuming and not 

efficient or sometimes not possible due to reach limitations. 

The junction in the open hole where geometries may not be 

necessarily uniform makes the task more difficult. Potential 

presence of washouts around the junction may affect the 

performance of the tool used to do the selective access. A trial 

and error process may then be needed to access the branch in 

such cases. After acid fluids have been pumped, the condition 

of the junction may change, enlarging the original diameter, 

due to acid reaction. The absence of downhole data makes 

this task more challenging. 

Traditional practices have been limited to spot stages of 

preflushes, acid, and diversion systems in front of the 


formation from toe to heel without proper control over the 

placement process. In the past, several stimulation treatments 

in dual lateral wells have not achieved the objective of 

increasing production in spite of placing acid in both laterals 

— raising doubts about the effectiveness of the diversion or 

the placement of the fluids. 

During the stimulation job with conventional CT, there are 

several uncertainties proving that there is no control on the job: 

• Where are the thief zones 

• Are these thief zones hydrocarbon bearing or not 

• Where in the hole is the acid squeezed Is it at the CT 

bottom-hole assembly (BHA) nozzle depth 

• Does it matter where the CT end is positioned while 

spotting the treatment fluids 

• In the case of additional bullheading, will fluid go to the 

CT BHA nozzle depth, even if there is a thief zone at 

the heel 

• Is squeeze pressure below or above frac pressure 

• What is the downhole temperature during treatment 

• When should the pump diverter be used Where What 

volume should be pumped 

• Is the diverter working Is the next acid stage wasted to 

the same thief zone 

• What type of diversion fluid should be pumped into nonhydrocarbon 

bearing and hydrocarbon bearing zones 

• Do we have an adequate pumping sequence Should it 

be the same for all wells 

• Are the fluid volumes enough or too little 

• Is there an understanding of the injection profiles 

The availability of open hole logs helps in identifying the 

intervals with a higher probability of production. It is possible 

that one lateral holds a very good quality zone that 

predominates over the other, becoming a key target of the 

stimulation treatment. 

If one lateral contains predominantly higher permeability 

and porosity sections, it is also certain that most of the fluid 

volume has the tendency to go towards this section. In this case, 

it is likely that the damage is not removed and potential 

production in the other lateral is not unlocked. It would then be 

ideal to have a means to understand if this situation is taking 

place. Many of these questions can be addressed with real-time 

downhole measurements taken as the CT treatment progresses. 

Ultimately, the objective of the stimulation treatment in gas 

wells with open hole completions in Ghawar field includes: 

• Ensure uniform placement of acid into the targeted 

reservoir intervals. 

• Ensure efficient diversion to stimulate the targeted zones. 

• Avoid treating the same lateral twice. 

A case study of utilizing the latest CT advancements, in two 

dual lateral horizontal open hole gas producers, that 

demonstrates how to optimize a stimulation treatment as it 

develops, is described in this article. Using an innovative 

workflow — interpretation of distributed temperature survey 

(DTS) responses, correlated with reservoir data — it is possible 

to selectively place treatment fluids, maximizing the contact of 

stimulation fluids with the targeted formation sections. 

BACKGROUND 

Well A was completed as a dual lateral Khuff-C gas well 

producer. The well was completed with a 4½” tubing string. 

The well is cased with a 7” liner to the top of the producing 

reservoir at 11,623 ft measured depth (MD). The motherbore 

(L0) was then drilled successfully to a TD of 13,895 ft MD. 

After that, the lateral (L1) was drilled, with a junction at 

11,652 ft MD, to 15,331 ft MD. After drilling, the well was 

flowed back for cleanup but was not flowing. It was decided 

to stimulate the well, targeting as the main priority the L1 

section between 12,500 ft and 13,100 ft. 

Well B was completed as a dual lateral Khuff-C gas well 

producer. The well was completed with a 4½” tubing string. 

The well is cased with a 7” liner to the top of the producing 

reservoir at 11,471 ft MD. The motherbore (L1) was then 

drilled successfully to a TD of 14,858 ft MD (lower lateral). 

After that, lateral L2 (upper lateral) was drilled after opening 

a window in the 7” liner at 11,477 ft MD to 11,488 ft MD to 

14,625 ft MD. The well production was very poor. A decision 

to stimulate the two laterals was taken, Fig. 1. 

TVD (ft) 

TVD (ft) 

11200.00 

11250.00 

11300.00 

11350.00 

11400.00 

11450.00 

11500.00 

11550.00 

11600.00 

11650.00 

11700.00 

11200.00 

11250.00 

L1: Pilot hole 

L2: Lateral 

11300.00 

11350.00 

11400.00 

11450.00 

11500.00 

11550.00 

11600.00 

11650.00 

11700.00 

0 1000 2000 3000 4000 5000 

V-Section (ft) 

Fig. 1. Well A and B trajectories. 

0 1000 2000 3000 4000 5000 

V-Section (ft) 


Fig. 2. ACTive fiber optics. 

DESCRIPTION OF FIBER OPTIC ENABLED COILED 

TUBING (FOECT) TECHNOLOGY 

Optical fibers are widely used in communication due to the 

benefits they offer for data transmission. In an application to 

oil field services, a system based on fiber optics has been 

developed and adapted for use in CT operations, to enable 

downhole measurements in real time. 

FOECT system features include: 

• Fiber Optic Carrier (FOC) inside the CT string 

• The FOECT BHA 

• Surface acquisition 

• DTS system 

• Interpretation services 

The downhole tool includes a CT head that terminates the 

fiber optical connections; the electronic package that houses 

the downhole communication system; the battery, the sensors 

for internal and external pressure and temperature; and the 

Casing Collar Locator (CCL). The tool is flow through and 

made of acid and H 2 S resistant materials. 

The FOC, that has an outside diameter of 1.8 mm 

(0.071”), is previously installed in the CT string. The FOC is 

non-intrusive; therefore standard operations normally done 

with conventional strings can be carried out, including 

pumping corrosive fluids and dropping balls, Fig 2. 

On the surface, the downhole data is transmitted from the 

CT working reel, via wireless and without a collector, into the 

CT Control Cabin, where specialized software is used to 

acquire, display, monitor and record the parameters of the job 

in real time. The surface acquisition system also has the ability 

to communicate with the tool downhole to send commands. 

API format printouts of the operation parameters can be 

delivered in the field. 

As the fiber itself acts as a temperature sensor across the 

length of the CT string, a DTS monitoring system can also 

be used to capture reliable, accurate and real-time downhole 

distributed temperature profiles, along with data acqui - 

sition, analysis, and interpretation. There is no need for 

calibration points along the fiber or for calibrating the fiber 

prior to installation in the wellbore. The system enables 

monitoring thermal profiles of injection at different times 

during the treatment. 

To provide greater system integration — an interpretation 

specialist with reservoir production background and 

measurements expertise — identifies the downhole events and 

performs an analysis of the combined data with specialized 

software; to adjust the treatment, as many times as needed. 

The interpretation specialist, who can be on the well site or in 

the office, interacts with the stimulation and CT engineers, as 

well as the well engineers, to decide the next steps. 

MULTILATERAL SELECTIVE REENTRY TOOL (MSRT) 

The BHA used in the intervention also included the 

Multilateral Selective Reentry Tool (MSRT), which consists of 

a surface-controlled orienting tool and a controllable bent sub. 

The system identifies the window of the selected lateral before 

attempting reentry, and confirmation of successful identification 

and entry is visible at surface through a softwaredisplayed 

pressure log. The corrosion-resistant reentry tool is 

operated solely on flow and is conveyed with standard CT 

equipment. 

The MSRT profiles the lateral junction during the upward 

passes, Fig. 3, instead of rotating a full cycle at a specified 

depth, which is the technique for standard access tools. The 

Fig. 3. Multilateral selective re-entry tool operational sequence. 


orientation of the bent sub relative to the lateral window is 

changed with the orienting tool, indexing 12 times to cover 

360°. Even if the tool cannot be oriented, because the bent 

sub is locked in a washout, the upward movement of the 

wand allows the tool to flip in the desired orientation after the 

first few inches of movement. 

DESCRIPTION OF THE STIMULATION CAMPAIGN — 

APPLICATION OF FLUIDS, EQUIPMENT AND 

PROCESSES 

Two Khuff gas wells were treated with selective fluid 

placement based on DTS data. The treatment objective of 

Well A was to selectively enter the upper lateral — 

characterized by the best pay — for acid stimulation to 

enhance well production. Once a fluid injection profile would 

be established in the targeted lateral, an optimized stimulation 

treatment based on interpretation of the real time downhole 

data provided by the FOECT would be executed and 

evaluated for efficiency. The treatment objective of Well B was 

a similar optimized stimulation of hydrocarbon bearing pay in 

both horizontal open hole laterals. Each well would be treated 

with a fluid placement schedule, open for modification based 

on the well response to the treatment as observed and 

interpreted on-site by an interpretation specialist. Real time 

data from the FOECT system recorded during or after key 

stages of each treatment provided the downhole measurements 

necessary for interpretation of downhole events. 

The general procedure for optimized FOECT carbonate 

acid stimulation consists of the following stages: 

• Preflush injection. Warm back analysis, identification of 

potential thief zones. 

• Acid diagnostic stage. Heat buildup analysis, identification 

of potential thief zones, fluid placement 

schedule. 

• Acid treatment stage 1. Diversion analysis: Remedial 

corrections to fluid placement schedule. 

• Acid treatment stage 2. Diversion analysis: Further 

corrections to fluid placement schedule as required. 

• Post flush injection. Warm back analysis: Fluid 

distribution confirmation and treatment evaluation. 

Additional customized stages may be added as needed to 

aid interpretation and understanding of key downhole events 

or to record and document developments to the fluid injection 

profile during treatment. The detailed stimulation summary of 

Well A highlights the potential importance of this interactive 

approach to optimize the treatment, Fig 4. 

Well A - First run in hole (RIH): 

• CT was RIH from the surface. Break circulation was 

maintained with treated water. 

• CT stopped at 12,412 ft to record the geothermal 

gradient baseline. 

• FOECT data used for lateral confirmation (CT in target 

lateral L1). 

• Treatment fluids prepared for stimulation of main target 

pay in lateral L1. 

Well A - Preflush injection in lateral L1: 

• Starting from 12,445 ft, CT was RIH to 13,000 ft, then 

pulled out of hole (POOH) to 12,500 ft. 

• Preflush (125 bbl) was pumped while reciprocating 

the coil. 

• FOECT data analysis showed significant losses 

occurring to lateral L0 at the lateral junction. 

• Decision was made to pump an undiverted initial acid 

stage to remove potential skin damage. 

Well A - First acid stage in lateral L1: 

• CT was POOH from 13,000 ft - 12,600 ft while 

pumping acid, then RIH to 13,000 ft. 

• Treatment acid: 26% HCl acid (200 bbl). 

• FOECT data analysis showed continued losses to lateral 

L0 with little or no acid going to the formation in L1. 

• Decision was made to focus on diversion from lateral 

L0 without exiting lateral L1. L0 Log is showing 50 ft 

close to the heel with double gas saturation compared 

to other gas bearing zones in L0 and L1. 

Well A - Foam and viscoelastic self-diverting acid to divert 

from lateral L0 while maintaining CT inside lateral L1: 

• CT pulled to 12,000 ft to pump foamed and viscoelastic 

self-diverting acid to lateral L0 (CT still 300 ft inside 

lateral L1). 

• Diverter: 20 bbl foam and 10 bbl viscoelastic selfdiverting 

acid pumped nitrified to lateral L0. 

Well A - Second acid stage in lateral L1: 

• CT was reciprocated from 13,000 ft - 12,600 ft while 

pumping acid, then RIH 13,100 ft for analysis. 

Fig. 4. Well completion for Well A. 


• Treatment acid: 26% HCl acid (150 bbl). 

• FEOCT data analysis showed reduced losses to lateral 

L0 and increased acid effects in the target lateral L1 in 

an interval extending 200 ft above the expected target 

pay (12,400 ft - 12,700 ft) with little acid effect across 

300 ft of the pay. 

• Decision was made to pump nitrified viscoelastic selfdiverting 

acid, prior to a final acid stage targeting the 

under-stimulated 300 ft of the main pay with stationary 

acid injection in three stages. 

Well A - Placement of nitrified viscoelastic self-diverting acid 

in L1 before final acid stage: 

• CT was POOH from 13,000 ft - 12,400 ft while placing 

diverter, then RIH to 13,000 ft prior to final acid stage. 

• Diverter: 200 bbl nitrified viscoelastic self-diverting 

acid. 

Well A - Final L1 acid stage: 

• CT was POOH from 13,000 ft - 12,600 ft, stopping at 

key targets at 12,900 ft, 12,800 ft and 12,750 ft in the 

main pay. 

• Treatment acid: 26% HCl acid (250 bbl). Ten bbl acid 

was pumped stationary at each of the three target points. 

• FEOCT analysis showed further increased acid effects 

across the 12,400 ft - 13,000 ft interval, covering the 

entire main pay and extending 200 ft above it. 

• Decision was made to pump post flush while POOH to 

profile for lateral L0 entry with the MSRT. 

Well A - Stimulation of lateral L0: 

• Several attempts were made to access lateral L0 after 

profiling the open hole junction with the MSRT. Despite 

many attempts, the MSRT did not allow access to lateral 

L0, suggesting washout of the open hole junction beyond 

what was expected during the job design. Consistent 

losses throughout the acid treatment of lateral L1 may 

have contributed to deteriorate the condition of the open 

hole junction prior to MSRT profiling. 

• Decision was made to pump the treatment with CT 

stationary 100 ft above the lateral junction. To avoid restimulating 

lateral L1, the decision was taken to fill up 

this lateral (13,000 ft - 12,000 ft) with foam. 

• The treatment targeting L0 was pumped stationary at 

11,600 ft: 

- Nitrified preflush (50 bbl). 

- Five stages of nitrified 15% HCl viscoelastic selfdiverting 

acid (50 bbl each) followed by nitrified 

26% HCl acid (100 bbl each). 

- Post flush (120 bbl). 

This concluded the treatment of Well A. FOECT DTS data 

from key stages of the stimulation treatment is included in 

Appendix A Fig. 1. 

Fig. 5. Well completion for Well B. 

Following is the detailed stimulation summary of Well B, 

Fig 5: 

Well B - First RIH – natural pass confirmation (targeting 

lateral L2): 

• CT was RIH from surface. Break circulation maintained 

with treated water. 

• CT stopped at 11,800 ft for lateral confirmation with 

FOECT data (400 ft below lateral window). 

• FOECT data gave positive indication that, CT natural 

pass was the non-target lateral L1. 

• Decision was made to profile the window with MSRT 

to enter lateral L2. 

Well B - MSRT profiling for lateral L2: 

• CT was reciprocated across the lateral window to 

acquire the MSRT profile. Once established, CT was 

RIH attempting access to lateral L2. 



• FOECT data gave positive indication that CT was again 

in the nontarget lateral L1. 

• Decision was made to re-profile the window with 

MSRT to enter lateral L2. 

Well B - MSRT re-profiling for lateral L2: 

• CT was reciprocated across the lateral window to 

reacquire the MSRT profile. Once established, CT was 

RIH attempting access to lateral L2. 



• FOECT data gave positive indication that CT was in the 

target lateral L2. 

• CT was run beyond L1 TD confirming that CT is 

indeed in L2. 

• Decision was made to perform a clean out of lateral L2 

(a 2 7 ⁄8” high-pressure jetting tool was used), tag TD for 

a secondary lateral confirmation and inject preflush 

across the lateral L2 open hole. 


Well B - Preflush injection lateral L2: 

• Preflush was pumped while RIH to TD. 

• FOECT data analysis showed three potential thief zones 

at 12,300 ft -12,480 ft, 12,740 ft - 12,800 ft and 

12,900 ft - 13,000 ft. No losses were observed to occur 

at the lateral window. 

• Decision was made to target the potential thief zones 

with nitrified 26% viscoelastic self-diverting acid while 

POOH and injecting 26% viscoelastic self-diverting acid 

across the other target zones while RIH. 

Well B - Diversion and acid stages in lateral L2 (500 bbl of 

26% viscoelastic self-diverting acid): 

• CT was POOH from 14,800 ft - 11,550 ft, then RIH to 

14,800 ft. 

• Diverter: nitrified viscoelastic self-diverting acid pumped 

across the thief zones while POOH. 

• Treatment acid: 26% viscoelastic self-diverting acid 

pumped across the target zones while RIH to TD. 

• FOECT data analysis showed good diversion in the 

intervals 12,300 ft - 12,480 ft and 12,900 ft - 13,000 ft, 

but continued fluid loss to the interval 12,740 ft - 

12,800 ft. No losses at lateral window. 

• Decision was made to re-target the remaining potential 

thief zone with diversion, prior to a final acid stage 

targeting the main pay with stationary acid injection at 

three selected points, followed by post flush injected 

across the entire open hole section of lateral L2. 

Well B - Post flush injection profile in lateral L2: 

• CT was RIH from 11,550 ft - 14,800 ft (TD). 

• Post flush was pumped while RIH. 

• FOECT analysis showed an almost uniform injection 

profile with residual diversion still in effect across the 

interval 12,740 ft - 12,800 ft. No losses at lateral window. 

• Decision was made to proceed to POOH to the lateral 

window and enter the CT natural pass lateral L1 for 

stimulation. 

Well B - Natural pass confirmation (targeting lateral L1): 

• CT was pulled above the lateral window, then RIH 

attempting access to lateral L1. 



• FOECT data gave positive indication that CT was in the 

target lateral L1. 

• Decision was made to perform a clean out of lateral L1, 

tag TD for a secondary lateral confirmation and inject 

preflush across the lateral L1 open hole. 

Well B - Preflush injection lateral L1: 

• Preflush was pumped while RIH to TD. 

• FOECT data analysis showed no potential thief zones in 

the lateral pay. Indication of fluid loss to the toe is noticed. 

• Decision was made to pump foam across 13,900 ft - 

13,800 ft to prevent downhole fluid loss. Then 26% 

viscoelastic self-diverting acid will be pumped across the 

target zone. 

Well B - Diversion and acid stages in lateral L1 (250 bbl of 

26% viscoelastic self-diverting acid): 

• Diverter: foam pumped across 13,900 ft - 13,800 ft. 

• Treatment acid: 26% HCl viscoelastic self-diverting acid 

pumped while RIH across target zone 12,660 ft - 

13,630 ft. 

• FOECT data suggested good diversion of the foam as 

no downhole fluid loss could be observed. An even 

temperature distribution further suggested that uniform 

fluid distribution was achieved. 

• Decision was made to proceed with the final post flush 

stage. 

Well B - Post flush injection profile in lateral L1: 

• Post flush was pumped while RIH to end of target zone. 

• FOECT analysis indicated a near uniform injection 

profile. No losses were observed at the lateral window. 

• Decision was made to proceed with nitrogen kick-off 

and final POOH. 

This concluded the treatment of Well B. 

RESULTS 

Successful stimulation of target zones in both Well A and B 

was achieved with optimized smart fluid placement. Uniform 

acid coverage across the target zones was achieved by 

monitoring fluid placement, and diverting with the required 

volumes of nitrified viscoelastic self-diverting acid across the 

identified thief zones. Significant improvements to the fluid 

injection profile were observed after treatment. 

In Well A, excessive loss of treatment fluids to the non-key 

lateral L0 was avoided by the early identification of lateral 

losses and subsequent mitigation with foam and nitrified 

viscoelastic self-diverting acid diversion techniques. Confir - 

mation of gradually reduced losses to the thief zone in lateral 

L0 was observed. 

In Well B, early lateral identification prevented the need for 

tagging TD, which saved time and CT pipe cycling. Complete 

loss of all stimulation fluids to the toe was avoided by early 

identification of the thief zone and subsequent mitigation with 

foam diversion techniques. 

Based on offset wells and the type of completion, initial 

production expectations for Wells 1 and 2 were 12 MMscf/ 

day and 10 MMscf/day, respectively. For Well 1, poststimulation 

production increased 92% above expectations to 

23 MMscf/day. For Well 2, post-stimulation production 

increased 140% above expectations to 24 MMscf/day, Fig. 6. 


25 

20 

15 

10 

5 

0 

Well 1 Well 2 

Production before Stim 

Production Expected by Client 

Production after Stim 

• Real time adjustment of pumping schedule (fluid type 

and volume) based on DTS response. 

• Stop thinking that CT is a diversion means as treatment 

fluids will be squeezed into thief zones even with the use 

of high-pressure jetting tools (fluids can even travel back 

to a different lateral looking for the less resistant path). 

• Stop pumping predetermined stages of acid and diverter 

from toe to heel without any real time monitoring of 

fluids placement and diverter efficiency. 

Well production beyond expectation was achieved thanks 

to the smart fluid placement. 


The authors thank Saudi Aramco and Schlumberger 

management for permission to publish and present this article. 

REFERENCES 

Fig. 6. Post-stimulation production. 

CONCLUSIONS 

FOECT DTSs were used during matrix acidizing of two bilateral 

horizontal gas wells to optimize acid coverage and well 

productivity. 

Cleanout and stimulation of each wellbore was facilitated 

with a 2 7 ⁄8” high-pressure jetting tool. Lateral access and 

lateral confirmation was enabled by the use of the MSRT and 

real time DTS measurements. 

In each well, placement of the main treating fluid was 

modified real time based on the temperature response 

observed with DTS profiles. Treatment fluid loss to the lateral 

window/junction or to the toe could be confirmed with 

downhole measurements and controlled with real time 

modifications of the treatment fluid pumping schedule. DTS 

profiles, after each of the modified acid treatment stages, 

indicated significant incremental improvements towards 

uniform fluid placement, compared to the pre-stimulation 

preflush injection profiles. Post flush evaluation in each lateral 

further confirmed diversion efficiency of the chemical diverter. 

Downhole FOECT data supported by real time 

interpretation during key stages of the treatment resolved the 

uncertainties associated with conventional acid stimulation of 

multilateral open hole carbonate wells, and enabled proper 

control of CT stimulation jobs. Optimum acid coverage of 

target zones can be achieved through the following: 

• Identification of accessed lateral. 

• Identification of gas/non-gas bearing thief zones before 

and during stimulation, which will assist us in deciding 

the type and volume of diverter when required to pump 

it. Identification of fluids placement and diversion 

efficiency. 

1. Al-Zain, A., Duarte, J., Haldar, S., et al.: “Successful 

Utilization of Fiber Optic Telemetry Enabled Coiled Tubing 

for Water Shut-off on a Horizontal Oil Well in Ghawar 

Field,” SPE paper 126063, presented at the SPE Saudi 

Arabia Section Technical Symposium and Exhibition, 

al-Khobar, Saudi Arabia, May 9-11, 2009. 

2. Wortmann, H., Peixoto, L.P., Leising, L., Bunaes, C. and 

Nees, E.: “Selective Coiled Tubing Access to all 

Multilaterals Adds Wellbore Construction Options,” SPE 

paper 74491, presented at the IADC/SPE Drilling 

Conference, Dallas, Texas, February 26-28, 2002. 

3. Al-Buali, M., Al-Arnaout, I., Al-Shehri, A., Halder, S. and 

Al-Driweesh, S.: “Case History: Successful Application of 

Combined Rotary-Jetting and MLT to Stimulate Dual 

Lateral Producer in Ghawar Field,” SPE paper 119675, 

presented at the SPE Middle East Oil & Gas Show and 

Conference, Bahrain International Exhibition Centre, 

Manama, Bahrain, March 15-18, 2009. 

4. Parta, P.E., Parapat, A., Burgos, R., et al.: “A Successful 

Application of Fiber Optic Enabled Coiled Tubing with 

Distributed Temperature Sensing (DTS) Along with 

Pressures to Diagnose Production Decline in an Offshore 

Oil Well,” SPE paper 121696-MS, presented at the 

SPE/ICoTA Coiled Tubing & Well Intervention Conference 

and Exhibition, The Woodlands, Texas, March 31 - April 

1, 2009. 

5. Hadley, M.R., Brown, G.A. and Naldrett, G.: “Evaluating 

Permanently Installed Fiber Optic Distributed Temperature 

Measurements Using Temperature Step Resolution,” SPE 

paper 97677, presented at the SPE International Improved 

Oil Recovery Conference, Asia Pacific, Kuala Lumpur, 

Malaysia, December 5-6, 2005. 

6. Hadley, M.R. and Kimish, R.: “Distributed Temperature 

Sensor Measures Temperature Resolution in Real Time,” 


SPE paper 116665, presented at the SPE Annual Technical 

Conference and Exhibition, Denver, Colorado, September 

21-24, 2008. 

7. Smith, R.C. and Steffensen, R.J.: “Interpretation of 

Temperature Profiles in Water Injection Wells,” SPE paper 

4649, presented at the SPE-AIME 48 th Annual Fall Meeting, 

Las Vegas, Nevada, September 30 - October 3, 1973. 

APPENDIX A – SUPPORTING FIGURES AND FOECT 

INTERPRETATION EXAMPLES 

In treatment of the two candidate wells, the targeted upper 

lateral of Well A was selectively entered by use of the MSRT, 

and the CT was RIH for stimulation of the hydrocarbon 

bearing pay zone. While RIH a geothermal temperature 

profile was recorded (Fig. A1, green temperature curve) to 

Nitrified chemical diverter 

Foamed water 

8/10/2009 11:44 p.m. Preflush 

8/10/2009 5:08 a.m. Lateral Confirmation 

8/11/2009 6:30 a.m. 1st Acid 

8/11/2009 5:13 p.m. Acid and Diverter 

8/12/2009 5:56 a.m. Acid Jetting 

EOL at 11,624 ft 

Lateral Junction at 11,710 ft 

Fig. A1. Well A, L1 FOECT data from key treatment stages. 

Fig. A2. Well B, L1 FOECT data providing lateral confirmation. 


Fig. A3. Post flush temperature response (green) highlighting diversion effects obtained as compared to the preflush injection profile (blue) in Well B, lateral L1. 

establish a lateral junction baseline dataset for interpretation 

of the following recorded data. Reaching TD, preflush was 

injected and squeezed to formation through the CT while 

reciprocating once across the open hole. The warm back 

FOECT data following the preflush injection is highlighted in 

Fig. A1 in light blue. 

Interpretation of the FOECT preflush warm back data, 

suggests that significant losses occur to the non-targeted 

lateral L2, indicated with an orange line on Fig. A1. As fluids 

are pumped through CT in a well, a combination of 

convection heating of the pumped treatment fluids and 

convection cool-down of the surrounding wellbore by the 

passing of the colder fluids pumped from surface takes place. 

In cases where the fluid pumped is lost to a zone above the 

CT nozzle, the combination of convection heating of the fluid 

and convection cool-down of the wellbore typically results in 

a step change in temperature across a zone or a lateral 

junction to which significant fluid loss occurs. In Well A, 

lateral L1, the pumped preflush is being heated through 

convection both while being pumped through the CT and 

while traveling up hole in the L1 CT-wellbore annulus 

towards the lateral junction of lateral L2. The effect on DTS 

profile data of the losses of heated injected fluid to the 

junction is a significant step change from the convection 

cooled wellbore above the lateral junction to the heated fluid 

entering the lateral junction from below. Identifying such 

losses early in the treatment allows for immediate remedial 

actions to be taken, to reduce the volumes pumped and lost to 

other laterals. 

In Well B, both laterals were to be stimulated, but the 

measured TD of the two laterals (L1 and L2) was less than 250 

ft apart, Fig. A2. An early lateral confirmation was in this case 

achieved with the FOECT by running 400 ft into the natural 

pass lateral. Recording FOECT data while surface injecting 40 

bbl treated water to the CT-wellbore annulus provided a small 

but measurable cool-down across the wellbore. With the CT in 

the main bore, the 4½” tailpipe acted as severe downhole flow 

restriction preventing fluid flow (and the associated cool-down) 

below the tailpipe. Figure A3 shows the FOECT temperature 

data recorded before, during and after surface injection, giving 

an early positive lateral confirmation 400 ft into the lateral. As 

two attempts were required for positive confirmation of entry 

to the desired L2 lateral, this early warning avoided the need 

for three full trips to tag TD for lateral confirmation, saving a 

total of 8,800 running ft in the operation. 

Overlaid against the preflush injection profile in blue, Fig. 

A3 shows the post flush temperature profile in solid green. By 

comparing the pre- and post flush profiles, the diversion 

efficiency of the pumped may be evaluated. A near uniform 

temperature trend is now observed across the treated open hole 

section stimulation of lateral L1 in Well B. This suggests that a 

more uniform injection profile across the targeted pay has been 

achieved through diversion during the stimulation treatment. 

Another important observation is the lack of any 

observable temperature anomalies across the lateral window 

to the main bore. This confirms that the treatment fluids 

pumped to stimulate the target lateral were not lost through 

the lateral window. 


BIOGRAPHIES 

Francisco O. Garzon joined Saudi 

Aramco in 2005. He currently works 

as a Lead Engineer in the Hawiyah 

unit. Including his time with Saudi 

Aramco, Francisco has more than 20 

years of experience in the oil industry, 

working for Oxy, Schlumberger and 

BP. His expertise includes petroleum engineering and well 

interventions, well performance optimization using 

open/cased logs, production history, NODAL and pressure 

transient analysis information, coiled tubing and 

stimulation operations (chemical and hydraulic fracturing), 

workover interventions and artificial lift optimization. 

Francisco received his B.S. degree in Petroleum 

Engineering from the Universidad de America, Bogotá, 

Colombia in 1984 and his M.S. degree in Petroleum 

Engineering from Heriot-Watt University, Edinburgh, 

Scotland in 1991. 

J. Ricardo Amorocho is a Senior 

Petroleum Engineer consultant with 

the Hawiyah Engineering Unit in the 

Gas Production Engineering Division 

(GPED) in ‘Udhailiyah. His work 

supports coiled tubing operations, 

e-Line stimulation and well work 

intervention. Ricardo has 16 years of diversified oil 

industry work, of which 10 years were with BP working in 

various assignments, mainly in Colombia on well 

intervention on CT, CTD and stimulation. 

Since joining Saudi Aramco in 2006, Ricardo has been 

involved in a wide variety of well intervention activities 

with special emphasis on coiled tubing operations, 

horizontal well cleanouts and stimulation, and fishing 

operations. 

Ricardo received his B.S. degree in Petroleum 

Engineering in 1993 from the Fundacion Universidad de 

America in Bogota, Colombia. 

Moataz M. Al-Harbi is a Gas 

Production Engineer assigned to the 

Haradh Engineering Unit in the Gas 

Production Engineering Division 

(GPED) in ‘Udhailiyah. He has 13 

years of diversified oil industry 

experience. 

In 1996 Moataz received his B.S. degree in Mechanical 


Minerals (KFUPM), Dhahran, Saudi Arabia. After 

graduation, he joined Schlumberger where he specialized in 

stimulation operations. Moataz then joined Saudi Aramco 

in 2004, and is currently participating in the Production 

Engineering Specialist Program (PESP) as a Stimulation and 

Fracturing specialist candidate. He has been actively 

involved in the successful implementation of a number of 

new technologies aimed at enhancing well productivity, and 

is a mentor to young Saudi engineers. 

Nayef S. Al-Shammari joined Saudi 

Aramco in 1995 as a Production 

Engineer. He worked in different 

organizations (one year as Reservoir 

Engineer and two years as Well 

Services and Completion Engineer). 

Nayef has headed the Gas Well 

Services & Completion Division, South Ghawar Well 

Services Division, North Ghawar Well Services Division, 

Khurais and Central Arabia Well Services Division, ABQQ 

Production Engineering Division, Gas Production 

Engineering Division and the HRDH Gas Production 

Engineering Unit. He is currently a Supervisor in the Gas 

Production Engineering Division covering AinDar, 

‘Uthmaniyah and Shedgum’s Production Engineering 

Division. 

Nayef received his B.S. degree in Petroleum Engineering 

in 1995 from King Fahd University of Petroleum and 


Azmi A. Al-Ruwaished is a Production 

Engineering assistant Superintendent 

in the Southern Area Production 

Services Department (SAPSD), where 

he is involved in gas production 

services, well completion and 

stimulation activities. He is mainly 

interested in the field of production engineering, production 

optimization and new well completion applications. 

Azmi has been working with Saudi Aramco for the past 

15 years in areas related to production engineering and gas 

completion operations. 

In 2000, Azmi received his B.S. degree in Petroleum 

Engineering from Louisiana State University (LSU), Baton 

Rouge, LA. 

He is member of the Society of Petroleum Engineers 

(SPE). 

Mohammad Ayub is currently working 

with the Planning Unit as a Supervisor. 

He joined Saudi Aramco in 1982 and 

has held various positions in the 

Southern Area Production Engineering 

Department (SAPED) and the 

Southern Area Production Services 

Department (SAPSD). 

Mohammad received his B.S. degree in Petroleum and 

Gas Engineering from the University of Engineering and 

Technology, Lahore, Pakistan. 

He is member of the Society of Petroleum Engineers 

(SPE). 


Wassim Kharrat has been working 

with Schlumberger since September 

1998 in several countries around the 

world, including Tunisia, Germany, 

Libya, the United States and Saudi 

Arabia. He built his technical and 

operational expertise in coiled tubing 

and matrix stimulation. Currently, Wassim is working as a 

Coiled Tubing District Technical Engineer in ‘Udhailiyah 

with a focus on introducing and implementing ACTive new 

technology (real-time monitoring with fiber optic) for all 

types of coiled tubing jobs. 

In 1998, he received his M.S. degree in Mechanical and 

Industrial Engineering from École Nationale Supérieure 

d'Arts et Métiers (ENSAM), France. 

Vsevolod Bugrov received his M.S. 

degree in Petroleum Engineering in 

2003 from the Russian State University 

of Oil and Gas, Moscow, Russia. After 

graduation he started his career with 

Schlumberger as a Coiled Tubing 

Engineer. 

He has 6 years of experience in well intervention and 

stimulation services, including various applications of 

coiled tubing in arctic and desert conditions. Currently, he 

works in ‘Udhailiyah providing technical support for the 

Southern Area Production Engineering Department 

(SAPED) Coiled Tubing operations. 

Jan Jacobsen is the ACTive Domain 

Champion for Schlumberger in the 

Middle East. He joined Schlumberger 

as a Coiled Tubing Field Engineer in 

2004, working in Germany and The 

Netherlands. In 2007 Jan joined 

Schlumberger Data Consulting Services 

for assignments in the U.K. and France. He then joined 

Schlumberger Well Services and Data Consulting Services in 

his current position in Saudi Arabia in 2009. 

In 2004, Jan received his M.S. degree in Civil 

Engineering from the Technical University of Denmark, 

Copenhagen, Denmark, specializing in applied geophysics. 

George Brown joined Sensa in March 

1999 as the Manager of Interpretation 

Development and is currently 

Schlumberger’s Temperature 

Interpretation Advisor. (Sensa was 

bought by Schlumberger in 2001). He 

is responsible for developing the 

interpretation methodology and software to facilitate the 

analysis of Schlumberger’s permanent and intervention 

deployed distributed temperature measurements and has 

been analyzing distributed temperature data since 1999. 

Before Sensa, George spent 15 years with BP 

Exploration where he was Head of the Petrophysics group 

at the Sunbury Research Center and later Senior Formation 

Evaluation Consultant working with BP’s “Intelligent 

Wells” team charged with developing new permanent 

monitoring systems for horizontal and sub-sea wells, which 

included the early trials and evaluation of fiber optic 

temperature measurements. 

Prior to BP, he spent 12 years with Schlumberger 

Wireline working in both the Middle East (Saudi Arabia, 

Dubai and Turkey) and the North Sea area (Aberdeen and 

Norway) in a variety of operational and management 

positions. 

George holds a first class honors degree in Mechanical 

Engineering, has published over 20 technical papers, been 

awarded several patents and was a Society of Petroleum of 

Engineers’ (SPE) Distinguished Lecturer during 2004/5. 

Vidal Noya is a Coiled Tubing Services 

Technical Manager assigned to the 

region of Saudi Arabia, Kuwait and 

Bahrain. He has 19 years of experience 

in the oil field services. Since joining 

Schlumberger, he has worked in several 

projects related to operations and 

technology in the area of well intervention and production. 

Vidal’s experience includes assignments in South America, 

North Africa, the Middle East and Europe. 

He received his B.S. degree in Mechanical Engineering in 

1991 from the Universidad Central de Venezuela, Caracas, 

Venezuela. 


Successful Deployment of Multistage 

Fracturing Systems in Multilayered Tight Gas 

Carbonate Formations in Saudi Arabia 

Authors: Hasan H. Al-Jubran, Stuart Wilson and Bryan Johnston 

ABSTRACT 

Horizontal wellbores have enabled significant increases in 

productive zone contact areas. With these increased contact 

areas, the expected long-term production increases were not 

initially realized with conventional stimulation techniques. 

Multistage fracturing systems have resulted in impressive longterm 

production improvements, but the deployment of these 

assemblies into deep and long reach horizontal wells was 

initially problematic. After the original difficulties were 

encountered, modifications were made to the well preparation 

and assembly running procedures, which resulted in the recent 

successful deployment of several multistage fracturing systems 

into long reach horizontal wells in the Khuff formation in 

Saudi Arabia. 

This article will discuss several factors impacting the 

deployment of assemblies in these conditions, including: 

• Construction of the wellbore. 

• Deploying through multiple layers with varying 

reservoir pressures. 

• Preparation of the wellbore. 

• Running in hole techniques and procedures. 

With the implementation of these well preparation and 

deployment techniques, several multistage fracturing 

assemblies have been successfully installed allowing proper 

placement of multiple fracturing jobs, which have in turn 

resulted in continued production improvements from tight gas 

formations. 

INTRODUCTION 

Completions History 

In recent years, horizontal well drilling technologies have 

advanced, such that operators are now able to drill 

horizontally many thousands of feet into productive zones. 

There were high expectations that the resulting increase in 

contact area would, on its own, result in production 

improvements. In many instances, the expected production 

increases from barefoot or pre-drilled liners in horizontal 

wellbores was not realized. Damage caused by drilling fluids 

was determined to be the root cause of the production 

impairment of horizontal wells. The most commonly applied 

remedy for wellbore damage has been stimulation treat - 

ments in the form of proppant fracturing, acid fracturing or 

matrix acidizing. 

Initial attempts to improve production of horizontal wells 

through conventional (bullhead) stimulation techniques were 

disappointing. Stimulation treatments would find the weakest 

zones in the horizontal wellbore, such as areas of high 

permeability or the heel of the well, where all the treatments 

would be directed leaving the rest of the horizontal interval 

untreated 1 . Post-stimulation production logging revealed that 

the majority of production came from a single segment, the 

location of which was inconsistent being either at the heel, 

middle or toe of the well. Acid washing also resulted in only 

short-term and incremental production increases. It was 

deduced that mechanical diversion was required to compartmentalize 

long horizontal wellbores to allow for individual 

stimulation treatments to each compartment, or stage. 

Multistage Stimulation Systems 

Multistage stimulation systems (MSSs) and their use in 

horizontal well stimulation have been previously described in 

detail 2, 3 . Briefly, MSSs were first developed in 2002 using 

open hole packers on liners with sliding sleeves between each 

set of packers. These systems allowed for fracture stimulation 

of individual sections of a wellbore based on reservoir characteristics 

and production targets. 

The MSS consists of ball-actuated or hydraulicallyactivated 

sliding sleeves that are isolated using single or 

dual-element hydraulically activated mechanical (hydromechanical) 

packers. The ball seats in the ball-actuated sliding 

sleeves increase in size incrementally, such that the sleeves can 

be actuated in succession from toe to heel in a single, 

continuous operation. After well stimulation, the actuation 

balls are typically flowed back to the surface. This technique 

enables the entire horizontal wellbore to be stimulated and 

has resulted in significant production improvements enabling 

horizontal wellbores to achieve their full production potential. 

Khuff Formation in Saudi Arabia 

Saudi Aramco is using MSSs in the Khuff formation in the 

Haradh field located in east central Saudi Arabia to achieve 


SAUDI ARAMCO EXPERIENCE WITH INCOMPLETE 

DEPLOYMENT OF MSS 

For Saudi Aramco, the first installation attempts of MSSs in 

deep gas wells resulted in some systems not being able to be 

deployed to the desired depths. The high production rates 

obtained, even with incomplete deployment, resulted in an 

interest to identify the reasons for partial deployment and 

resolve these issues 6, 7 . The following section discusses the 

investigation process and the steps taken to achieve successful 

deployment of MSSs for Saudi Aramco. 

MECHANICAL STICKING 

After the first incomplete deployment of an MSS in 2007, the 

evidence seemed to point towards mechanical sticking as the 

root cause. There are several causes of mechanical sticking, 

including foreign objects left in the wellbore, ledges, and high 

dogleg severity (DLS). 

Foreign Objects in the Wellbore 

Fig. 1. Map of the Haradh field location in Saudi Arabia. 

maximum reservoir contact, Fig. 1. The Khuff formation is a 

highly heterogeneous deep gas carbonate reservoir consisting 

of several horizons, which vary significantly in permeability 

and porosity 4, 5 , Fig. 2. The Khuff-C is the main reservoir unit 

and produces high-pressure gas with varying amounts of H 2 S. 

Wells targeting the Khuff-C must go through the lowerpressure 

A and B zones complicating both the drilling and 

completion phases of well development. 

Foreign objects left in a well after drilling and before deployment 

of a completion assembly can result in severe damage to com - 

pletion components, or they can get wedged between the 

completion and the wellbore resulting in stuck pipe. Saudi 

Aramco has long recognized the importance of having a clean 

wellbore and has implemented procedures to clean the open hole 

and the casing prior to running completion assemblies. In many 

instances, the open hole and casing cleanup assemblies can be 

combined in one run to minimize rig time. The cleanup assemblies 

are inspected after each run and if the debris traps are full, or if 

large volumes of debris are observed, the cleanup assembly run is 

repeated until there is minimal or no debris returned. 

Fig. 3. Ability of drilling string to negotiate ledges in the wellbore. 

Fig. 2. Stratigraphic chart of the Khuff formation. 

Fig. 4. Inability of the completion string to negotiate ledges in the wellbore. 


Wellbore cleanup trips had been made in the early MSS 

deployments for Saudi Aramco. The likelihood that foreign 

objects in the wellbore were causing the deployment issues of 

the MSSs in Saudi Aramco wells was considered low. 

Ledges 

Wellbores are typically drilled with a drill bit then reamed 

with a watermelon-type mill. Drill bits can “deflect” when 

encountering harder formations or after making connections. 

This deflection can result in “steps” in the wellbore, which are 

easy for the bit and watermelon mill to negotiate, but difficult 

for the much stiffer liner pipe and tools, Figs. 3 and 4. A 

completion assembly is normally much stiffer than a drilling 

assembly, and typically contains tools with a larger outside 

diameter (OD). 

Ledges are also more common where the well is drilled in 

the minimum in-situ stress direction crossing several fracture 

planes or faults. Ledges can occur in areas where the fracture 

planes are crossed resulting in minor break outs of the 

formation face. In the case of the early wells drilled for the 

MSSs in Saudi Aramco, the wells were drilled in the maximum 

in-situ stress (i.e., parallel to the fracture plane). 

This ledge phenomenon was recognized when MSSs were 

first deployed and was addressed early in the history of 

running these systems. A gauge/reamer assembly was designed 

to simulate the larger OD and stiffer components of the MSS, 

Figs. 5a and 5b. The OD of the gauge/reamer is larger than 

the OD of the liner components but smaller than the inside 

diameter (ID) of the wellbore. The gauge/reamer bottom-hole 

assembly (BHA) is designed to be very stiff and before running 

the MSS, sliding this BHA into the wellbore is first attempted. 

If tight spots are encountered, then the drillpipe is rotated and 

reciprocated until the BHA is able to slide easily through the 

section. The intention is not to make the hole large, only to 

enable passage of the MSS liner. 

The gauge/reamer assembly was run on the initial MSS 

deployment for Saudi Aramco. No significant tight spots were 

encountered during this gauge/reamer trip. The likelihood that 

the incomplete deployment of the MSS was caused by ledges 

was considered low. 

Nevertheless, to ensure the wellbores in subsequent Saudi 

Aramco wells are free of ledges, doglegs or any other type of 

obstruction, the reamer BHA was made up with two reamers 

separated by a drill collar or joint of heavy weight drillpipe, 

Figs. 5a and 5b. By making this reamer assembly as stiff as 

possible, any potential problem areas are identified and 

resolved before the liner is deployed. 

Dogleg Severity (DLS) 

Saudi Aramco has used geosteering to move the wellbore 

towards “sweet” spots (i.e., those containing gas) identified by 

the “look ahead” logging while drilling (LWD) technology. If 

this technology is applied too often while drilling a well, and if 

the moves are too abrupt, the resulting wellbore can have 

multiple undulations. The deployment of any kind of liner into 

such tortuous wellbores can be very problematic. The first MSS 

deployed for a Saudi Aramco deep gas was into a well that had 

been geosteered. The DLS of this well was not very high, but 

this was considered as a most likely cause for the liner not 

reaching total depth (TD). To increase the potential for 

successful deployment, all subsequent MSS candidate wells for 

Saudi Aramco were drilled with rotary steering. The DLS of the 

rotary steered wells has been negligible. 

The second deployment of an MSS for Saudi Aramco deep 

gas occurred in August 2007. All the precautions to avoid 

mechanical sticking were implemented for this well. The open 

hole section for this well was originally intended to be 

approximately 4,000 ft, but upon completion of drilling the 

logs, it showed no hydrocarbons in the lower half of the well. 

The MSS was successfully deployed for the upper half of the 

well and the production results were once again noteworthy. 

While attempting to deploy an MSS into a third deep gas 

well in 2008, the assembly became stuck with approximately 

half of the liner into the open hole. There was much 

discussion about where the assembly was stuck and the cause. 

Pipe stretch calculations were conducted and it was 

determined that the stuck point was near the toe of the 

assembly. Comparison with drilling records for that well 

revealed that the drilling assembly had been stuck on at least 

three occasions at almost the same point while drilling the 

well. Examination of log data revealed that the toe of the MSS 

was across a low-pressure zone. It was an ideal set of 

conditions for differential sticking. 

DIFFERENTIAL STICKING 

Figs. 5a and 5b. Gauge/reamer tool used to locate and smooth out ledges in the 

wellbore. 

According to the Schlumberger Oil Field Glossary 8 , the 

definition of differential sticking is: A condition whereby the 

drilling or completion assembly cannot be moved (rotated or 


eciprocated) along the axis of the wellbore, Fig. 6. For 

example, the completion string can get stuck in filter cake that 

was previously deposited on a permeable zone. Differential 

sticking typically occurs when high contact forces caused by 

low reservoir pressures, high wellbore pressures, or both, are 

exerted over a sufficiently large area of the downhole assembly. 

The pipe is held in the cake by a difference in pressures 

between the hydrostatic pressure of the mud and the pore 

pressure in the permeable zone. A relatively low-differential 

pressure (delta p) applied over a large working area can be just 

as effective in sticking the pipe as can a high-differential 

pressure applied over a small area. The force required to pull 

the pipe free can exceed the strength of the pipe. 

Mitigation of Differential Sticking with Centralizers 

With the knowledge that differential sticking was the most 

likely cause of deployment issues for the MSS, the task was to 

determine how to overcome these challenges. The most readily 

available tool to combat differential sticking is centralization 

of the pipe so that it stands off the wellbore. Although it is 

widely recognized that centralized pipe is much less prone to 

differential sticking, many operations personnel strongly 

oppose the use of centralizers because of the increased risk of 

mechanical sticking. They cite occasions where they have 

attempted to run centralized liners, but could not get them to 

the bottom. In these cases, they pulled the liners back to 

surface, removed the centralizers, and then were able to force 

the liner to TD. 

It was immediately realized that the ledge phenomenon that 

had been identified early in the deployment of MSS was 

possibly the same issue that had caused the problems with 

deployment of centralized liners. If so, the gauge/reamer tool 

that had been successfully used to address the mechanical 

sticking issues for early MSS could also solve the problem 

with mechanical sticking when using centralizers. 

It was also noted that the centralizers had not been run in 

both previous cases where the MSSs had become stuck. 

Therefore, the lack of centralization was considered to be the 

most significant factor contributing to the MSS becoming stuck. 

Other Steps Taken to Reduce Sticking Potential 

Several other steps were taken to improve the chances for 

successful deployment of MSS assemblies. 

First, it was noted that on the wells where the MSSs had 

become stuck, that the 9 5 ⁄8” casing had been set above the 

lower-pressure zones, Fig. 7. The MSSs had to be conveyed 

through these zones before reaching the target depth. To 

mitigate this issue, candidate wells were selected where the 

open hole would not go through zones with widely ranging 

formation pressures, thereby minimizing the potential for 

differential sticking, Fig. 8. 

Second, the mud weights in some previous MSS wells had 

been excessively high, up to 2,000 psi overbalanced compared 

to the pore pressures in the lower pressurized zones, resulting 

in differential sticking conditions. Because of the variation in 

formation pressures, when the mud weight was increased to 

provide adequate hydrostatic pressure for the high-pressure 

zone, Fig. 7 – Zone 4), the low-pressure zones, Fig. 7 – Zones 

1 and 2, were over pressured, creating conditions for 

differential sticking. The mud quality itself is also influential 

in the probability for differential sticking. A thick, solids laden 

mud cake is more likely to cause sticking issues than a thin 

Fig. 7. Differential sticking of completion string due to open hole going through 

low-pressure zones. 

Fig. 6. Differential sticking as viewed in a cross-section of the wellbore 8 . 

Fig. 8. Candidate wellbores where the open hole does not go through low-pressure 

zones. 


mud cake. Low gravity solids should be kept as low as 

possible. Lubricity of the mud also plays an important role in 

minimizing the sticking effect. Therefore, the mud weights and 

solids content in subsequent candidate wells were reviewed to 

keep the overbalance as low as practicable without 

compromising safety. 

Third, use of the reamer BHA previously mentioned, will 

also help to reduce the thickness of the filter cake. The thicker 

the filter cake, the bigger is the cross-sectional area that the 

formation pressure acts on. Therefore, the differential sticking 

force is higher when the mud cake is thicker. 

Additionally, several run in hole procedural changes were 

implemented to minimize the potential for differential 

sticking. Documentation on the subject notes that the 

potential for differential sticking increases with the length of 

time that pipe is stationary across lower-pressure zones. It was 

therefore resolved that steps would be taken to reduce the 

time that the pipe would be stationary when in the open hole. 

Once the running string was set in the slips, the elevators were 

quickly moved up to pick up the next stand. This stand was 

immediately connected and the string was pulled out of the 

slips and the MSS run in was continued. There were no stops 

for filling the running string; instead, a fill up hose was used 

to add mud to the running string while the elevators were 

picking up the next stand. As soon as the stand was ready to 

be connected, the fill up hose was removed. There were no 

pauses during crew change; the focus was on keeping the pipe 

moving at all times while in the open hole section. 

Steps to Take if a Liner Becomes Differentially Stuck 

As noted above, the force holding the pipe against the 

wellbore can exceed the tensile strength of the liner or tools in 

the liner. When drilling a well or when tripping, if differential 

sticking is encountered, the immediate response by drilling 

personnel is to push, pull and twist – whatever is required – to 

get the pipe free. Drilling assemblies can take a lot of 

punishment, but liner assemblies cannot. Experience has 

shown that if an MSS liner becomes differentially stuck, the 

only way to free it is to incrementally reduce the mud weight 

(and therefore overbalanced pressure) until the wellbore 

releases the pipe. 

PROBLEM SOLVED 

The next MSS that was deployed had rigid, spiral centralizers 

on the middle of each joint of pipe that was run into the open 

hole, Fig. 9. All of the other differential sticking precautions 

mentioned above were also conducted during the installation 

of this system. The system was run to TD without any 

sticking incidents. In fact, after the assembly was on bottom 

for 30 minutes it was necessary to move the pipe to space out 

– and it continued to move freely. 

Since then, three more MSSs have been successfully run 

into Saudi Aramco deep gas wells. All systems have been 

deployed to TD without any sticking incidents. 

Fig. 9. Rigid, spiral centralizers installed on the middle of each joint of pipe to 

mitigate differential sticking. 

CONCLUSIONS 

Any liner or casing string is susceptible to differential sticking 

if the wellbore has one or more low-pressure zones, a high 

mud weight and excessive overbalance relative to the lowpressure 

zone(s). The MSSs are particularly susceptible to 

differential sticking because the large diameter tools can 

scrape filter cake off the wellbore exposing the low-pressure 

formation to the high wellbore hydrostatic pressure. The 

following are liner running practices incorporated by Saudi 

Aramco to help ensure their MSSs are deployed to TD. 

1. Where possible, drill the well so that the liner does not 

need to be run through nonproductive higher up zones 

with low formation pressure. Ideally, the casing shoe 

should be in the production interval. 

2. Reduce the mud weight to a safe, yet manageable, level to 

avoid over-pressuring the weaker zones. 

3. Proper centralization of the pipe can reduce, if not 

eliminate, the potential for differential sticking. 

4. The stiff gauge/reamer assembly that is run prior to 

running a MSS will identify and remove all ledges in the 

wellbore. This will dramatically reduce, if not eliminate, 

the potential for mechanical sticking of the MSS 

components and the centralizers. 

5. Minimize the time that the liner is stationary in the open 

hole. The potential for differential sticking increases with 

the amount of time the pipe is not moving due to the filter 

cake tending to buildup around the pipe and then 

increasing the differential sticking force. This includes 

minimizing connection time, no circulation breaks until the 

liner is at TD, and no pauses during crew change. 

6. If the MSS assembly does become differentially stuck, do 

not use excessive force to attempt to free it. Incrementally 

reduce the mud weight until the well releases the pipe and 


then either continue running the assembly or pull it out to 

inspect and re-run. 


The authors would like to thank the management of Saudi 

Aramco and Schlumberger for their permission to publish this 

article. The authors would also like to thank Maria Meijer, 

Adam Mei and Jackie Bourgaize at Packers Plus Energy 

Services for their assistance in the preparation of this 

manuscript. 

REFERENCES 

1. McDaniel, B.W., East, L. and Hazzard, V.: “Overview of 

Stimulation Technology for Horizontal Completions 

without Cemented Casing in the Lateral,” SPE paper 

77825, presented at the SPE Asia Pacific Oil and Gas 

Conference and Exhibition, Melbourne, Australia, October 

8-10, 2002. 

2. Seale, R., Donaldson, J. and Athans, J.: “Multistage 

Fracturing System: Improving Operational Efficiency and 

Production,” SPE paper 104557, presented at the SPE 

Eastern Regional Meeting, Canton, Ohio, October 11-13, 

2006. 

3. Seale, R.: “An Efficient Horizontal Open Hole Multistage 

Fracturing and Completion System,” SPE paper 108712, 

presented at the SPE International Oil Conference and 

Exhibition, Veracruz, Mexico, June 27-30, 2007. 

4. Al-Fawwaz, A., Al-Musharfi, N., Butt, P. and Fareed, A.: 

“Formation Evaluation While Drilling of a Complex 

Khuff-C Carbonate Reservoir in Ghawar Field, Saudi 

Arabia,” SPE paper 105232, presented at the SPE Middle 

East Oil and Gas Show and Conference, Manama, Bahrain, 

March 11-14, 2007. 

5. Al-Fawwaz, A., Al-Musharfi, N., Butt, P. and Fareed, A.: 

“New Era of Formation Evaluation While Drilling of 

Complex Reservoirs in Saudi Arabia,” SPE/IADC paper 

106596, presented at the SPE/IADC Middle East Drilling 

Technology Conference and Exhibition, Cairo, Egypt, 

October 22-24, 2007. 

6. Solares, J.R., Franco, C.A., Al-Marri, H.M., et al.: 

“Successful Multistage Horizontal Well Fracturing in the 

Deep Gas Reservoirs of Saudi Arabia: Field Testing of a 

Promising Innovative New Completion Technology,” SPE 

paper 114768, presented at the CIPC/SPE Gas Technology 

Symposium 2008 Joint Conference, Calgary, Alberta, 

Canada, June 16-19, 2008. 

7. Solares, J.R., Franco Giraldo, C.A., Al-Marri, H., et al.: 

“Successful Deployment of Innovative Completion 

Technology Designed for Multistage Fracturing Treatments 

in Horizontal Producers Achieved Significant Rate Increase 

in Saudi Arabia,” SPE paper 114766, presented at the SPE 

Annual Technical Conference and Exhibition, Denver, 

Colorado, September 21-24, 2008. 

8. Schlumberger Oilfield Glossary: 

http://www.glossary.oilfield.slb.com/Display.cfmTerm=diff 

erential%20sticking. 


BIOGRAPHIES 

Hasan H. Al-Jubran is a Production 

Specialist with the Gas Production 

Engineering Division of the Southern 

Area Production Engineering 

Department (SAPED). He has 17 years 

of oil production experience. 

In 1992, Hasan received his B.S. 

degree in Petroleum Engineering from King Fahd University 

of Petroleum and Minerals (KFUPM), Dhahran, Saudi 

Arabia. 

He is a member of the Society of Petroleum Engineers 

(SPE). 

Stuart Wilson is a Schlumberger Area 

Manager for Multistage Completion 

business. He has 13 years of 

completion and coiled tubing 

experience. 

Stuart received his B.S. degree in 

Mechanical Engineering from 

Hertfordshire University, Hatfield, England, and his M.S. 

degree in Business and Operations Management from the 

Norwegian Institute of Technology, Trondheim, Norway in 

1997. 


(SPE). 

Bryan Johnston is a Packers Plus Area 

Business Development Coordinator. He 

has 20 years of cementing, stimulation 

and downhole tool experience. 

Bryan received his technical diploma 

and MBA degree from the University 

of British Columbia, Vancouver, British 

Columbia, Canada. 


(SPE). 


Application of Hydrajetting Technology 

Achieves Significant Productivity Increase in 

Saudi Arabian Gas Producers 

Author: Emad A. Al-Abbad 

ABSTRACT 

Stimulating gas reservoirs, particularly in horizontal producers, 

has presented a considerable challenge to Saudi Aramco; as 

wellbore accessibility is difficult in wells drilled in deeper 

formations, with relatively low permeability and high-pressure 

and temperature. Therefore, conventional perforating and 

stimulation methods have not been as successful as expected 

when applied in single and dual-lateral completions. 

Alternative techniques, based on hydrajetting technology, have 

been recently applied in a number of underperforming 

horizontal gas producers with excellent results. The technology 

is used to create slots along the horizontal section and then 

perform pinpoint acid stimulation treatments. The acid is 

displaced in the zones in most need of stimulation, resulting in 

significant well productivity and economic enhancement. This 

article details the methodology that has been used to apply 

hydrajetting technology, and highlights the successful results 

and benefits achieved in a number of field trials. 

INTRODUCTION 

The majority of Saudi Aramco’s gas producers, targeting 

reservoirs in deep and tight formations, are being drilled 

horizontally to optimize field development, achieve maximum 

reservoir contact and reduce overall cost. Stimulation 

treatments are required on a number of these producers, 

because their productivity is frequently impaired by either 

drilling damage or poor reservoir quality. The conventional 

stimulation methods applied early in the field development 

history, which included bullheading acid at high-pressure and 

rate conditions, and performing coiled tubing (CT) acid 

washes, did not improve well productivity at the expected 

level 1 . This was not entirely surprising given the difficulty of 

placing treatment fluids — in targeted zones in need of 

stimulation along lengthy open hole horizontal completions — 

in the presence of thief zones, washouts and highly hetero - 

geneous reservoir conditions. The problems — associated with 

initiating and extending hydraulic fracturing treatments in 

vertical wells, drilled in some of the tightest formations and 

perforated with conventional methodologies — led to the 

search for nonconventional methods, capable of overcoming 

the high fracture initiation pressure experienced in these wells. 

An innovative hydrajetting tool was developed and field tested 

for the first time in a vertical gas producer; with reservoir 

characteristics similar to other wells where attempts to 

perform proppant hydraulic fracturing treatments resulted in 

premature screenouts. The same technique, in combination 

with other innovative approaches, was later successfully used 

to perform acid stimulation treatments in a number of 

underperforming horizontal open hole producers with 

excellent results. 

HYDRAJETTING OVERVIEW 

Hydrajetting is a technology that applies a high-velocity 

stream of fluid, carrying small abrasive particles, to create 

slots into the hydrocarbon bearing reservoir, Fig. 1 2 . Details of 

a typical fluid mixture used during hydrajetting operations are 

shown in Table 1, and steps of a typical pumping sequence of 

a hydrajetting stage are shown in Table 2. The typical bottomhole 

assembly (BHA), Fig. 2, is commonly run on CT during a 

slotting operation, and the BHA is usually comprised of the 

following: a hydrajetting tool, a CT connector, a motor head 

assembly, an anchor to prevent axial movements, a multicycle 

Fig. 1. Illustration of three different targets of hydrajetting and the respective sizes 

of the jetting cavities 6 . 

Additive Unit Concentration 

Descrition 

(per 1,000 gal) 

Getting Agent lbs 46 

Surfactant Gal 22 

Proppant lbs 1,000 

Brine Gal 990 

Table 1. Example of jetting fluid mixture comprising the main erosive slurry used 

in hydrajetting 


Step Description Fluid Type Average CT Rate (BPM) Time (min.) 

1 Preflush (for the first stage only) Gelled Brine 2.5 ~ 3.0 20 

2 Erosive Perforating Gel with Sand 2.5 ~ 3.0 12 

3 Flush Gel 3 20 

4 Bottoms-Up Circulation Gel 2.0 ~ 2.5 72 

5 Reduce pumping rate and locate CT in the next desired depth, and repeat steps 2-5. 

Table 2. Pumping sequence for one stage of hydrajet perforation 

and the formation. Conventional methodologies had achieved 

only limited success in the same wells. Figure 3 shows the 

results from a field test showing the characteristics of the hole 

size and shape created with a hydrajetting tool. 

Fig. 2. Typical BHA schematic of a hydrajetting tool. 

FIRST FIELD TRIAL: HYDRAJET ASSISTED FRACTURING 

A number of carbonate reservoirs being developed in Saudi 

Arabia require a high rate of stimulation to maximize well 

productivity and meet field development objectives. As 

previously highlighted, most of the wells in these reservoirs 

are being drilled as open hole horizontal completions, which 

presents a considerable challenge when trying to achieve 

effective stimulation throughout the entire horizontal section, 

or to perform pinpoint stimulation in targeted under 

producing zones. 

The hydrajetting technology was first tested in Well A, a 

vertical exploration well drilled in a tight sandstone reservoir 

to a depth in excess of 16,000 ft. The well required hydraulic 

fracturing stimulation, and had similar reservoir characteristics 

to other wells in the area conventionally perforated. 

In these wells, the hydraulic fracturing attempts had to be 

aborted when the maximum allowable downhole pressure was 

reached; either before initiating a fracture or screening out 

prematurely early into the treatment. A hydrajetting tool was 

used to create long large diameter slots using abrasive jetting 

slurry, reducing the fracture initiation pressure. The jetting 

induced slots achieved deep and clean penetration with a 

minimal crushed zone effect, as the jetting slurry cuts through 

the formation and carries debris out through the CT annulus 3 . 

The hydraulic fracturing treatment was successfully 

performed in Well A. A total mass of 135,500 lbs of 20/40 ISP 

proppant was displaced into the formation, without any 

incremental tool to set nozzles precisely on target, and a 

jetting sub with multiple nozzles 3 . The jetting velocity of a 

hydrajetting tool ranges from 20,000 ft/sec to 30,000 ft/sec, 

exerting a pressure of approximately 4 million psi on the 

target zone 4 . The tool is also designed to withstand 

differential pressure greater than 10,000 psi and has a 

temperature rating of about 350 °F 5 . Saudi Aramco has 

successfully field tested this technique in long horizontal open 

hole completions. The jetting induced slots were excellent 

conduits of stimulation treatment fluids between the wellbore 

Fig. 3. Results from a field test showing the characteristics of the hole size and 

shape created with a hydrajetting tool (courtesy of Halliburton). 


Amount of Proppant (lb) 

135,600 lb 135,550 lb 

140,000 

120,000 

100,000 

80,000 

60,000 

40,000 

20,000 

0 

10,637 psi 

100,200 lb 

17,000 psi 

Fig. 4. Comparison of hydraulic fracturing treatments in wells with similar 

reservoir characteristics. 

problems, at a maximum surface treatment pressure of 10,600 

psi. Figure 4 shows the results of hydraulic fracturing 

treatments performed in Wells A, B, C and D, which were 

perforated with conventional perforating guns. 

OTHER HYDRAJETTING APPLICATIONS 

0 lb 

Acid Stimulation in a Vertical Well 

110,984 lb 

11,773 psi 

65,340 lb 

173,000 lb 

10,144 psi 

A B* C D 

Well Name 

Amount of Prop. Planned 

Amount of Prop. Placed into Formation 

Maximum Treatment Pressure 

50,541 lb 

18,000 

16,000 

14,000 

12,000 

10,000 

8,000 

6,000 

4,000 

2,000 

After the first successful application of hydrajetting in a 

vertical well drilled in a sandstone reservoir, it was recognized 

by the technical team that the methodology and tools could be 

enhanced and used to perform pinpoint acid stimulation 

treatments, in both vertical and horizontal wells. Massive 

hydraulic fracturing acid stimulation treatments have been 

successfully used by Saudi Aramco to achieve multifold rate 

increases in vertical gas producers; drilled in carbonate 

reservoirs since the beginning of the gas development 

program. The effectiveness of such treatments has been 

enhanced by mixing liquid or solid diverting agents with 

treatment fluids, to achieve a more uniform fluid entry 

distribution in the multiple perforated intervals. Poststimulation 

surveillance data has shown effective diversion in 

wells, with multiple perforated intervals with close proximity. 

In wells with significant separation between perforated 

intervals, the effectiveness of diverting agents is lower. 

Therefore, it was decided to apply the hydrajetting technique 

in one of the wells — with multiple perforated intervals with 

significant separation — for which a matrix stimulation 

treatment was prescribed. The slots were created in the lower 

quality reservoir zones in Well E to evenly displace treatment 

fluids throughout all the perforated intervals. The treatment 

was successfully pumped and the post-stimulation gas rate 

achieved was about 50% higher than the pre-stimulation rate. 

Moreover, post-treatment logging data showed that all 

perforated intervals were contributing to the flow. A 

comparison between the pre- and post-stimulation gas rates is 

shown in Fig. 5. 

0 

Maximum Treatment Pressure (psi) 

Acid Stimulation in a Horizontal Well 

The productivity enhancement results achieved in horizontal 

producers when using conventional stimulation techniques 

(e.g., acid washes with CT and high rate bullheading 

treatments), have not met expectations. The effectiveness of 

such treatments is heavily dependent on being able to access 

and successfully place the treatment fluids into the targeted 

sections of the formation. This treatment is a challenging task, 

particularly in wells completed open hole in tight formations, 

and in cased wells with clogged perforations. 

The decision was made to apply the hydrajetting technique in 

an open hole underperforming horizontal gas producer. The 

slots were to be created in different zones along the long 

horizontal section, and then a pinpoint acid stimulation 

treatment at matrix conditions would be done. The treatment 

was successfully implemented in Well F by creating slots in the 

lowest quality reservoir sections along the horizontal length, and 

then pumping a multistage acid treatment with a diverting 

agent. The expectation from this approach was to maximize the 

ability of the acid to bypass the high quality reservoir zones and 

enter directly into the created fluid entry points. Post-stimulation 

results, Fig. 5, clearly indicate a highly successful treatment as 

indicated by the fourfold productivity increase achieved. 

Slotting a Highly Deviated Well 

Perforating a highly deviated cased hole, using conventional 

guns, run on e-Line, presents significant challenges. Most of 

the problems encountered are related to the yo-yoing effect 

experienced by the cable; due to the common tension changes 

found in the high angle or dogleg sections, which often result 

in stuck or stranded cable. Therefore, the hydrajetting 

technique was successfully tried, in lieu of conventional 

perforating, in Well G. This gas producer was drilled with a 

total measured depth exceeding 15,000 ft and a 73° angle. A 

90 ft net pay zone was then slotted by creating three 1” slots 

in each of the 12 hydrajetting stages, for a total of 36 slots. A 

CT acid wash was then performed and the well was put into 

production at an initial gas rate of 20 million standard cubic 

Gas Production Rates (MMscfd) 

30 

25 

20 

15 

10 

5 

0 

Pre -Stim. Post -Stim. Pre -Stim. Post -Stim. 

Well E 

Production Rate 

Well F 

FWHP 

2,500 

2,000 

1,500 

1,000 

Fig. 5. Comparison of pre- and post-stimulation rates for wells in which the 

hydrajetting technique was applied. 

500 

0 

FWHP (psi) 


feet per day (MMscfd) with a flowing wellhead pressure 

(FWHP) of 2,500 psi. The hydrajetting application in this well 

also resulted in an estimated 30% cost saving. 

THE WAY FORWARD 

Hydrajetting technology has allowed Saudi Aramco to 

successfully overcome some of the challenges in effectively 

stimulating complex producers. The successful results 

achieved in the different applications, highlighted throughout 

this article, have provided the incentive to continue to enhance 

the capabilities of the available tools for use in combination 

with others. In the next planned application of such a tool 

combination, a hydrajetting tool will be run — in tandem 

with a fiber optic fit CT capable of recording live pressure, 

depth and distributed temperature data — in Well H, a duallateral 

open hole gas producer. It is expected that the 

application of these technologies will allow the proper identification 

of the targeted lateral. The lateral will then be 

accessed to perform a pinpoint stimulation treatment using the 

hydrajetting technique. The ability to monitor the differential 

pressure across the jetting nozzles should help control the 

pumping rates. In addition, the monitoring will help avoid the 

splash back effect, known to occur when the jetting fluid 

creates a cavity that directs the fluid back with high velocity, 

into the jet body 6 . Results from this new application will be 

the subject of a future technical article. 

CONCLUSIONS 

1. The application of hydrajetting technology in multiple 

settings has helped Saudi Aramco to effectively stimulate 

vertical and horizontal gas producers. 

2. The post-stimulation results from the use of this technology 

have yielded a significant improvement over results 

achieved in offset wells (with similar reservoir characteristics), 

treated using conventional stimulation methods. 

3. The ability to effectively stimulate targeted zones along 

horizontal sections in open hole completions has been 

significantly enhanced, through the implementation of 

hydrajetting technology. 

4. Future planned applications of hydrajetting tools, in 

combination with other technologies, will continue to 

enhance our ability to effectively stimulate complex and 

difficult to access multilateral completions. 


The author would like to thank the management of Saudi 

Aramco and Saudi Aramco’s Gas Production Engineering 

Division for permission to publish this article, and to the 

engineers who shared information about the implementation 

of the jobs described. Special appreciation goes to J. Ricardo 

Solares for all of his guidance and technical expertise provided 

throughout the preparation of this article. 

REFERENCES 

1. Al-Harbi, M.: “Deployment of New Technologies for 

Horizontal Gas Producers,” Saudi Aramco E&P Sr. VP 

Interface Meeting, ‘Udhailiyah, Saudi Arabia, 2009. 

2. McDaniel, B.W., Surjaatmadja, J.B. and East, E.L.: “Use of 

Hydrajet Perforating to Improve Fracturing Success sees 

Global Expansion,” SPE paper 114695, presented at the 

CIPC/SPE Gas Technology Symposium Joint Conference, 

Calgary, Alberta, Canada, June 16-19, 2008. 

3. Solares, J.R., Amorocho, J.R. and Bartko, K.M., et al.: 

“Successful Field Trial of a Novel Abrasive Jetting Tool 

Designed to Create Large Diameter-Long Cavities in the 

Formation to Enhance Stimulation Treatments,” SPE paper 

121794-MS, presented at the SPE/ICoTA Coiled Tubing 

and Well Intervention Conference and Exhibition, The 

Woodlands, Texas, March 31 - April 1, 2009. 

4. Shah, S.: “Perforation Techniques,” Drilling and 

Completions II of the University of Oklahoma, PE 4323, 

2008, pp. 7-8. 

5. Schlumberger AbrasiJET Hardware Manual, 2009. 

6. McDaniel, B.W. and Surjaatmadja, J.B.: “Hydrajetting 

Applications in Horizontal Completions to Improve 

Hydraulic Fracturing Stimulations and Improve ROI,” SPE 

paper 125944, presented at the SPE Eastern Regional 

Meeting, Charleston, West Virginia, September 23-25, 

2009. 

BIOGRAPHIES 

Emad A. Al-Abbad joined Saudi 

Aramco in 2004 as a College Degree 

Program Non-Employee (CDPNE) 

participant. He then went to the 

University of Oklahoma, Norman, 

OK, where he earned a B.S. degree in 

Petroleum Engineering with special 

distinction in May 2009. During his studies, Emad was 

awarded the International Leadership Award, and the 

College of Earth and Energy Outstanding Junior and Senior 

awards in 2008 and 2009, respectively. In June 2009, he 

joined the Southern Area Production Engineering 

Department (SAPED) working for the Gas Production 

Engineering Division. 

Emad is a member of the Society of Petroleum Engineers 

(SPE) and a member of its Young Professional and Student 

Outreach Committee. 


Development and Optimization of 12” PDC 

Bit for Powered Rotary Steerable Systems in 

Deep Gas Drilling in Saudi Arabia 

Authors: Saeed H. AbdRab Al-Reda, Abdullah A. Al-Kubaisi, Khalid Nawaz, Muhammed F. Jamil, Octavio Alvarez, 

Baseem E. Qattawi, Jaywant Verma and Sukesh Ganda 

ABSTRACT 

Directional drilling the 12” curve section in the deep gas fields 

in Saudi Arabia is very challenging because of the hard 

formations and harsh drilling conditions. The area consists 

primarily of hard limestone and dolomites interbedded with 

anhydrite. The main challenges of drilling this area include 

multiple bit trips and reduced rates of penetration (ROP). 

To overcome these challenges, the operator, directional 

drilling service company, and drill bit company, in collabo - 

ration, developed an optimization process to create and evolve 

a polycrystalline diamond compact (PDC) bit design to be used 

on powered rotary steerable systems (PRSSs). 

The objective of the optimization process was to increase 

the ROP and the durability of existing PDC bits to eventually 

lead to drilling longer intervals by minimizing the number of 

bit trips while drilling with PRSSs. The challenge required the 

development of a new PDC technology in conjunction with 

optimized drilling practices and a reliable drive system. 

The challenges were overcome by implementing the specific 

bit design algorithms incorporated with new cutter 

technology, and using drilling simulation software to optimize 

the bit cutting structure design in a directional drilling 

environment. Significant improvements in bit design were 

achieved after closing the model/measure/optimization loop. 

Through field testing, drilling parameter evaluation, and 

drilling simulation, a new 12” PDC bit was designed that 

established benchmark performances in the deep gas 

operations in the Ghawar field. 

The successful development of the PDC bit in conjunction 

with the PRSS led to record runs in the 12” build section. 

Casing-to-casing sections were drilled with an improved ROP 

of approximately 125%, compared to that of a conventional 

motor. This article reviews the bit design and optimization 

process to develop the fit-for-purpose PDC bit that helped to 

improve the drilling performance, significantly reduce rig 

days, and enable early delivery of the wells in challenging 

deep gas drilling in Saudi Arabia. 

extend throughout the eastern Arabian Peninsula and Arabian 

Gulf. Primary elements of these Paleozoic and Jurassic 

petroleum systems — source, reservoir, and seal rocks — are 

of great volumetric extent and exceptional quality. The 

combination of these regionally extensive petroleum system 

elements and the formation of large subtle structural closures, 

before peak hydrocarbon generation and migration, have 

produced oil and gas fields with extraordinary reserve 

volumes. The main gas reservoirs are the lower Khuff and 

Unayzah reservoirs, which are encountered between a depth 

of 12,500 ft and 13,500 ft, depending on the zone. Because of 

its intrinsic proprieties, the Ghawar field is divided into six 

zones (from north to south, Fazran, Ain Dar, Shedgum, 

‘Uthmaniyah, Haradh and Hawiyah), and each zone provides 

different drilling challenges, Fig. 1. 

To maximize the gas production and sometimes because of 

surface location constraints, the 12” section of the deep gas 

wells is typically drilled directionally through the base of Jilh 

dolomite, Sudair, and Khuff A, B, C or D, depending on the 

target. The most common well profile includes drilling 

vertically for a few hundred feet into the base of the Jilh 

formation and then kicking off the well at an approximate 

depth of 10,000 ft. In most cases, the azimuth is planned to 

remain constant through the section and the final inclination 

varies from 60° to 80°, depending on the well objectives. The 

average buildup rate (BUR) is 4°/100 ft, but some well plans 

demand up to 5°/100 ft. Wells drilled with positive dis - 

placement motors (PDMs) have resulted in several trips at a 

low rate of penetration (ROP) because of the rock hardness, 

steering issues, poor bit performance, and hole problems, such 

INTRODUCTION 

The greater Paleozoic and Jurassic petroleum systems of the 

Arabian Peninsula form one of the most prolific petroleum 

producing systems in the world. Source rocks of these systems 

Fig. 1. Ghawar field localization. 


as pipe sticking. In some parts of the field, the mud weight 

must be increased considerably because of the over pressure 

present in the Jilh formation, which increases the difficulty of 

drilling the section 1 . 

Rotary steerable system (RSS) tools were introduced into 

the Saudi Aramco deep gas operations to improve hole quality 

and ROP. To enable optimum steerability, stability, ROP, and 

bit life, it was necessary to develop a polycrystalline diamond 

compact (PDC) bit to match the system. 

After several bit optimization cycles and optimum drilling 

practices based on the accumulated experience, the latest 

iteration of the 12” PDC bit designed to match the powered 

rotary steerable systems (PRSSs) achieved multiple drilling 

records in most zones of the Ghawar field. Today, it is 

possible to drill the entire section in one run, which sig - 

nificantly reduces the drilling time and costs of the deep gas 

operations in Saudi Arabia. 

GEOLOGY OF THE 12” SECTION 

The geology of the 12” section, Fig. 2, includes the following 

formations. 

Base of the Jilh Formation 

The base of the Jilh formation consists primarily of carbonates 

(dolomitic limestone and dolomite) with streaks of anhydrite 

and shale. Because the Lower Jilh is known to be a highpressure 

zone, casing is set in the base Jilh dolomite to 

increase the mud weight to compensate for the high-pressure 

zone. The estimated formation pore pressure is 75 pounds per 

cubic foot (pcf) to 80 pcf equivalent mud weight, and it is 

drilled with a mud weight of 78 pcf to 90 pcf. The typical 

mud weight is 100 pcf. 

Sudair Formation 

The Sudair formation consists primarily of shale with streaks 

of anhydrite, siltstone and dolomitic limestone. The estimated 

formation pore pressure is 80 pcf to 82 pcf equivalent mud 

weight, and it is drilled with a mud weight of 90 pcf to 93 

pcf. The shale in the Sudair formation is reactive to hydration; 

bit and stabilizer balling is common in some zones of the field. 

Khuff Formation 

The Khuff formation is a highly intercalated formation that 

consists primarily of carbonates (limestone and/or dolomite 

and/or dolomitic limestone) with streaks of anhydrite and 

shale. The Khuff formation contains three gas reservoirs 

(Khuff A, B and C). Khuff A and B are medium hard 

formations, and Khuff C is more consolidated. 

WELL PROFILE 

Early directional wells used conventional motor systems. The 

vertical section was drilled with a performance motor and an 

aggressive PDC bit. The bit was then pulled out of the hole, 

Fig. 2. Stratigraphic column; formations drilled directionally. 

and the build section was drilled with a steerable motor 

bottom-hole assembly (BHA). Directional objectives could be 

achieved; however, drilling with a conventional motor BHA 

requires numerous bit runs and provides low ROPs. Before 

the introduction of the PRSS application, the average ROP 

when drilling a 12” curve section was approximately 10 ft/hr. 

Figure 3 shows the well profile. 

In a typical well design, 13 3 ⁄8” casing is set 30 ft into the 

base of the Jilh dolomite. A typical well profile requires 

vertical drilling approximately 800 ft to 1,000 ft with a 

performance motor and an aggressive PDC bit. The curve 

section is planned with a dogleg severity (DLS) of 

approximately 4°. The 9 5 ⁄8” casing was planned to be set into 

the Khuff C carbonate. It required an average of two to four 

bit trips to drill the curve section. The formations encountered 

while drilling the build section are hard, and because of the 

number of hours, bit wear, low ROP, and tool failures, 

additional trips were required. 

The objectives with the PRSSs were to drill both vertical 

and curve sections in one run, maximize the ROP, and 

increase the footage drilled per bit run, while meeting 

directional requirements. 

BIT PERFORMANCE WITH A STEERABLE MOTOR 

This section will discuss the bit performance with a steerable 

motor in a 12” section of the southern Ghawar field where 

the bit optimization process occurred. The hardness of the 

rock, transition zones, shale reactivity, and rock abrasiveness 

in the southern zones differs slightly between zones, which 

represents various bit design challenges. 


Vertical Section View 

10,000 

Well A LO 

Survey 

Base Jllh Dolomite 

TVD Scale - 1” = 996.176 ft 

11,000 

12,000 

13,000 

13 3 /8” Csg. Point 

10,220 ft MD, 10,201 TVD 

2.53º 274.85ºaz 

Sudair Formation 

Khuff - C Carbonate 

Khuff - C Reservoir 

Khuff Formation 

Khuff - A Reservoir 

Khuff - B Deservoir 

9 5 /8” Csg. Point 

14,000 ft MD 12,883 ft TVD 

71.42º 65.57ºaz 

Well A LO 

Survey 

14,000 

Well A LO 

Survey 

Projection at Bit 

17,812 ft MD 19,661 ft TVD 

68.00º 58.00ºaz 

Projection at Bit 

14,000 ft MD 13,416 ft TVD 

68.00º 65.57ºaz 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

6,000 

Vertical Section (ft) Azim - 65.2”, Scale - 1” = 896.176 ft Origis - 0 IN/-S,O E/-W 

7,000 

Fig. 3. Vertical section view of well design (dual lateral). 

Haradh Area 

In the Haradh area, stuck pipe incidents, bit balling issues, 

and high torque that affects the overall drilling performance 

are commonplace; an average of three runs are required to 

drill a 12” directional section with steerable motors. The first 

BHA is used to drill vertically with performance motors to the 

kickoff point, and then it is pulled out to pick up the 

directional tools. The second BHA is usually unable to reach 

the total depth because of bit or motor failure, making it 

necessary to run one or two more bits and/or motors to finish 

the interval. The average ROP for the section is 10.1 ft/hr. 

Figure 4 shows the motor drilling performance in the Haradh 

zone. 

Fig. 4. Motor performance in the Haradh 12” curve section. 

Hawiyah Area 

The formations in the Hawiyah area are harder, as compared to 

the Haradh area; the condition of the bits used through these 

formations typically show broken cutters and ring outs, and the 

average ROP for the section is 9.4 ft/hr. Figure 5 shows the 

motor drilling performance in the Hawiyah zone where it was 

necessary to use three to four PDC bits to complete the section. 

The typical mud weight is 100 pcf (13.5 ppg), but in some 

wells, the Jilh formation is over pressured, which requires 

increasing the mud weight up to 148 pcf (20 ppg). 

‘Uthmaniyah Area 

The ‘Uthmaniyah zone is similar in hardness to the Hawiyah 

area. The average ROP for the section drilled with PDC bits 

and steerable motors is 9.8 ft/hr, and two to three PDC bits, 

Fig. 5. Motor performance in the Hawiyah 12” curve section. 

on average, are required to complete the interval. A few wells 

have required up to five PDC bits to complete the same 

section because localized harder spots induce cutter impact 

damage on the bits. Figure 6 shows the motor drilling 

performance in the ‘Uthmaniyah zone. 


Fig. 6. Motor performance of the ‘Uthmaniyah 12” curve section. 

the-bit. Figure 7 shows a point-the-bit RSS tool used during 

this bit optimization exercise, which operates by offsetting the 

bit and creating a bend that changes the course of the well in 

the desired direction. The bit and tool body rotate at the same 

speed, and the magnitude of the bit tilting effect is controlled 

electronically from the surface. By eliminating the need to 

slide to follow the well plan, the system creates high quality 

wellbores that improve almost every aspect of drilling by 

lowering vibration, extending bit life, minimizing downhole 

tool failures, and increasing ROP. 

These systems operate by placing a relative bit offset bend in 

the system, much like a standard motor assembly. This bend is 

held geostationary (nonrotating) with respect to the formation. 

To understand the point-the-bit principle, one can make 

comparisons to conventional drilling systems that use motors 

or turbines. In a conventional system, a bent housing and 

stabilizer on the bearing section enables the motor to drill in 

either an oriented (sliding) mode or a rotary mode. In the 

rotary mode, the bit and the drillstring both rotate. The 

rotation of the drillstring negates the effect of the bent housing, 

and the bit drills an over gauge straight path parallel to the 

axis of the drillstring above the bent housing. In the sliding 

mode, only the bit rotates. The motor changes the well course 

in the direction of the bent housing, and the drillstring slides 

down the hole behind the bit. In the point-the-bit system, the 

bent housing is contained within the collar of the tool. This 

bent housing is controlled by means of an electric motor that 

rotates counter to the direction of and at the same velocity as 

the drillstring. This control enables the bent housing to remain 

geostationary while the collar is rotating. 

POWERED ROTARY STEERABLE SYSTEM (PRSS) 

Fig. 7. Point-the-bit RSS tool. 

ROTARY STEERABLE SYSTEM (RSS) 

RSSs have gained ground rapidly because they can 

revolutionize the way that directional wells are drilled. RSSs 

can be categorized by the mode of operation. There are two 

steering concepts for these systems: point-the-bit and push- 

A PRSS is a high-performance RSS with a fully integrated high 

torque power section that converts mud hydraulic power to 

mechanical energy, Fig. 8. This energy, combined with the 

rotation provided by the rig’s top drive, significantly increases 

downhole power at the bit. The additional torque capacity 

enables the use of aggressive PDC bits for directional 

application and greater weight on the bit, resulting in 

increased ROP and more cost-effective drilling. This system 

can drill faster and further. 

The integrated power section rotates the bit and enables the 

drillstring rotation to be slowed. Stick/slip and other 

damaging vibration modes common to conventional rotary 

drilling are reduced. All available energy is used to drill the 

hole optimally. Casing wear and drillstring fatigue is reduced 

as a result of slower drillstring rotation, which minimizes the 

possibility of drillstring or casing failure 2 . 

All external parts rotate at drillstring speed, which reduces 

drag. The rotation also helps to clean and condition the hole, 

reducing the risk of differential or mechanical sticking. 

For deep gas operations in Saudi Arabia, point-the-bit 

systems were used in conjunction with downhole power 

sections, i.e., PRSS. 


Fig. 8. Powered rotary steerable system. 

BIT DESIGN TOOLS 

To obtain the maximum potential from the PRSS, it was 

necessary to design a 12” PDC bit to match the system to get 

the proper gauge pad geometry (thickness, wrap and reinforce - 

ment), and to provide adequate cleaning and sufficient wellbore 

contact to limit over engagement and undercutting of the 

formation. In addition to the gauge configuration, which must 

match the PRSS for maximum tool steerability, the process of 

designing a bit to drill directionally through this tough interval 

provided a series of challenges that were addressed during the 

bit optimization process. The ultimate goal was to create a bit 

with the right profile and optimum cutting structure, and that 

provided efficient cleaning and adequate protection; it must also 

be steerable, stable, and durable, with a neutral walk tendency. 

To meet these challenges, several bit design analytical tools, 

including IBitS, Direction by Design (DxD), and computa - 

tional fluid dynamics (CFD) software, were used emphasizing 

bit steerability and stability. 

IBitS 

IBitS software is the bit designing tool platform that enables 

the bit designer to generate the cutter layout and to simulate 

the forces to which the bit will be exposed under specific 

drilling parameters. Depending on the cutter geometry and 

space position on the bit face, this tool can be used to 

calculate the torsional, axial, and lateral forces of each cutting 

element showing the total bit force imbalance as output. Force 

imbalance provides a good measure of the bit stability 

through homogenous intervals. The IBitS tool can also be used 

to calculate the bit force. It obtains low values by manipu - 

lating the cutter layout and enables increased bit energy levels 

by evenly distributing cutter forces. It also includes the 

transition drilling model, which helps to identify possible 

areas of impact damage when the bit moves from soft to more 

competent formations. 

Direction by Design 

Direction by Design software is a high-technology analytical 

tool that provides advanced bit design engineering to optimize 

directional performance. It provides a powerful means of 

optimizing the matched bit design for the specific directional 

application and drive system. The software eliminates lengthy 

and expensive trial-and-error bit design, making it possible to 

define the relationship between specific bit design changes and 

their full effect on the directional deliverables. This tool 

enables the bit designer to compare the performance of 

various bit designs before they are run. It was a key factor in 

reducing the learning curve during this optimization process 

of the 12” PDC bit used with the PRSS in the Ghawar field. 

The new DxD tool is based on a mathematical model 3 . 

Computational Fluid Dynamics 

This type of analyses was also performed during the bit 

optimization process to ensure that the new bits had the 

correct hydraulic configuration. Proper bit face cleaning is 

critical through the Sudair formation because of the reactive 

shale that can cause bit balling situations. 

CUTTER TECHNOLOGY 

During the last decade, the development of new PDC cutter 

technologies was based on improving the abrasion and impact 

resistance by using various components and interfaces with PDC 

table substrate geometries. In many applications, including the 

12” directional section in the Ghawar deep gas wells, the dull 

grade analyses showed what was believed to be impact damage 

because the PDC cutters were broken or chipped when they 


Fig. 9. Thermal integrity; the figure on the left shows good thermal integrity, and the figure on the right shows poor thermal integrity. 

Fig. 10. Bit A cutter layout. 

came out of the hole. Later analyses and laboratory tests 

concluded that in many cases what appeared to be impact 

damage was actually cutter degradation as a result of the high 

temperatures to which the cutters are exposed during the drilling 

operations. Based on this cutter failure mechanism, new cutters 

were developed to improve the wear and impact resistance, as 

well as the thermal integrity, Fig. 9. After many laboratory and 

field tests in various locations, including Saudi Arabia, cutters 

for extreme drilling conditions were developed and implemented 

in bits used in demanding environments, such as the deep gas 

wells in the Ghawar field. With the optimum distribution of 

forces on the 12” PDC bit design, cutters for extreme drilling 

conditions, and PRSS, it was possible to considerably extend the 

bit life to replace up to four PDC bits, as compared to the wells 

in which steerable motors and conventional PDC bits were used. 

12” PDC BIT DESIGN AND OPTIMIZATION 

Base Bit Design (Bit A) 

The first two bits used with the PRSS tool were basic designs 

that were used previously with conventional steerable motors 

and achieved relatively good results. Bit A was set with eight 

blades, 13, 16 and 19 mm standard cutters in the bit face, and 

13 mm cutters in the gauge. The gauge pad was straight and 

3” long. The first two runs in the Haradh zone were not too 

demanding from the steerability perspective; the results were 

encouraging because the system was able to kickoff the well 

Fig. 11. Bit A straight gauge pads. 

from the vertical, and the ROP was almost twice that 

obtained in the runs with conventional motors. Figure 10 

shows the distribution of the three cutter sizes on the Bit A 

face. Figure 11 shows the straight gauge pads. 

Bit Design Iteration 1 (Bit B) 

After analyzing and discussing the results with the operator 

and directional drilling company, it was evident the PRSS 


needed a fit-for-purpose bit design to match the system and to 

increase the steerability and stability, which were the weak 

points indentified in the first run with the PRSS. The first step 

included an in-depth analysis of Bit A to identify its strengths 

and weaknesses, and to establish an action plan for the next 

iteration. Among the strong points, it was clear that the use of 

eight blades and 19 mm cutters as the primary cutting 

structure provided a good balance between bit life and ROP; 

consequently, it was decided to continue with this geometry. 

Bit A recorded several vibration incidents, with slip-stick 

recorded at the surface and measured while drilling (MWD) 

shocks registered by the downhole tools. The cutters exhibited 

medium wear, and several chipped cutters indicated a need for 

improvements in the cutting structure. The force imbalance 

values, which were one of the few analytical components 

initially available when Bit B was designed, showed relatively 

high values. The ideal bit force imbalance scenario occurs 

when the values are near zero; values of less than 4% are 

accepted as the minimum standard. 

The cutting structure of the new Bit B included few 

changes, as compared with Bit A. To gain stability and 

improve the force imbalance values, the angle of the back 

rakes was adjusted by 15% to decrease the aggressiveness, 

and the blades were moved to obtain better figures. The 13 

mm cutters were eliminated in the bit face to increase the 

ROP, and the gauge length was reduced to 2½” to improve 

the steerability, particularly because planned future wells 

would require a greater BUR than the first two runs in the 

Haradh field. Rather than a straight gauge pad, Bit B used a 

spiral gauge, which considerably increased the borehole 

contact, Fig. 12. 

The cutter type in Bit B was updated to the Z3 ® cutter, 

which provided additional impact resistance. All force 

imbalance values were improved by up to 50%. 

Bit B was used in the next four wells, including two wells in 

the Haradh zone and two in the ‘Uthmaniyah zone. The 12” 

section in the ‘Uthmaniyah wells required building the angle 

from the vertical up to 74°, which tested the system’s 

steerability. In the first three wells of this batch, the 12” 

directional section was completed with one bit, but because of 

a long directional section in the last ‘Uthmaniyah well, the 

ROP became too low before the interval was completed, 

requiring the bit to be pulled out of the hole and the use of 

one more bit to complete the interval. Bit B showed better 

stability than Bit A; the steerability was good but not 

optimum because the PRSS had to be set at the maximum 

deflection in some intervals to achieve the required doglegs. 

The bit came out of the hole with a great deal of cutter wear, 

which explained the reduction in ROP that required the bit to 

be pulled out of the hole, Fig. 13. 

The Z3 cutter could not drill sections of more than 2,500 ft 

long because of the abrasiveness of the Khuff formation in the 

‘Uthmaniyah zone. This was the first well with such a long 

section, and it set a new challenge to be overcome. 

Fig. 12. Straight gauge pad vs. spiral gauge pad. 

Fig. 13. Bit B condition after drilling in the ‘Uthmaniyah zone. 


Bit Design Iteration 2 (Bit C) 

By the time the team was ready for a bit new design iteration, 

the Saudi Arabia operations bit designer used new analytical 

tools, including the energy balance and transition drilling 

modules. The cutting structure was optimized using the new 

tools, which further reduced the force imbalance and obtained 

minimum energy balance values. It was adjusted to obtain 

smooth transition drilling, simulating hard rock (35,000 psi 

compressive strength) and soft rock (10,000 psi compressive 

strength). Figure 14 shows the ability of the bit to return to an 

imbalance stage (flat lines) after drilling through a formation 

change, and Fig. 15 shows its maximum value at the bit nose, 

which is the right trend. 

Because the major challenge was to increase the bit life 

without sacrificing the ROP, Bit C implemented the use of a 

new PDC cutting element, R1 cutters. The R1 cutters act as 

a secondary cutting structure to assist cutting after the 

primary cutting structure begins to show some degree of wear. 

In addition to the additional diamond volume, the R1 cutters 

help to prevent impact damage and to control the depth of cut 

when the cutting structure is still in perfect condition. Figure 16 

illustrates the R1 cutter geometry. 

An additional improvement made to Bit C includes the 

rearrangement of the bit nozzle after the CFD indentified 

some interference zones in which the flow coming from the bit 

was re-circulated around the bit face before it was evacuated 

through the annulus space. 

Bit C provided many good runs in all Ghawar zones, 

completing the directional section in one run in 95% of cases. 

The bit condition at the end of the run improved substantially, 

and the bit achieved the optimum ROP while completing the 

interval. Figure 17 shows the smooth wear at the end of the 

run and the performance of the R1 cutters after the main 

cutting structure began to wear. 

Bit Design Iteration 3 (Bit D) 

In the last quarter of 2008, two new technological advances 

made it possible to increase the bit performance standard in 

the Saudi Arabia deep gas drilling operations. The devel - 

opment of the cutters for extreme drilling conditions, which 

Fig. 14. The ability of the bit to return to an imbalance stage (flat lines) after 

drilling through a formation change. 

Cutter Torque Change 

7 

6 

Percent Torque Change 

5 

4 

3 

2 

1 

0 

0 10 20 30 40 50 

Cutter Number 

Fig. 15. The maximum value at the bit nose. 

Fig. 16. R1 cutter implemented on Bit C. 


laboratory and previous field tests showed to be more 

abrasive and impact resistant, brought new possibilities to the 

bit design scenario. The availability of a stronger PDC cutter 

enabled a lighter set bit to be used in this application and 

increased the ROP. The introduction of the DxD simulator 

enabled the quantification and optimization of all bit features 

for an optimum product capable of increasing the bit 

directional performance. 

Bit D provides an example of the science underlying the bit 

design. This bit retained the original format of eight blades 

and 16 mm and 19 mm cutters in the face, but the diamond 

density was reduced by 25% by spacing out the cutters. This 

cutter count reduction is equivalent to a six or seven blade bit 

design. The DxD analysis indicated that by reducing the 

diamond density but retaining the number of blades, the bit 

stability was not affected; by performing additional 

adjustments to the cutter layout, even the stability of the 

torque on bit (TOB) variation was improved. Figure 18 shows 

the R1 cutters on the bit and the spacing between the cutters. 

The DxD tool also enabled improved bit steerability of Bit 

D. This tool made it possible to simulate the actual drive 

system (point-the-bit), drilling parameters, and basic 

formation properties, and compared the previous Bit C design 

with that of Bit D. 

By changing the gauge configuration to create a step gauge 

and reducing the tip grinding of the gauge cutters (more 

lateral aggressiveness), the steerability was improved by 57%, 

as compared with Bit C. The graphs shown in Figs. 19 and 20 

illustrate the results generated by DxD. Figure 21 shows the 

improved Bit D steerability. 

Improving the bit steerability means that the bit will require 

less side force to generate the planned doglegs; in extreme 

drilling conditions through hard formations, the PRSS tool 

output will be optimum in terms of doglegs. In soft and medium 

formations, the deflection on the PRSS shaft will be less, 

minimizing the stress on the tool and increasing its reliability. 

Fig. 17. R1 cutter in action – Ghawar field. 

Fig. 18. Bit D cutter distribution. 

Fig. 19. Bit steerability. 


Bit Control 

158 

160 

Drilling Torque (lbs - ft) 

113 

53 

13 

-38 

-58 

-138 

-158 

Bt C 

Bt D 

Torque Variations (lbs - ft.) 

140 

120 

100 

80 

60 

40 

20 

0 

0 

Bit C 

Bit D 

1 2 3 4 5 

The greater the Torque flucuation 

the less the Bit Face Control 

DLS (deg/100 ft) 

Fig. 20. Bit tool face control. 

Bit Walk 

Walk Angle 

Walk Angle 

Bit Name 

Bit Walk Force (lb) 

BitWalk Rate (100 ft) 

Bit Walk Angle (deg) 

Bit C 

-151.15 

-1.59 

-17.64 

Bit Name 

Bit Walk Force (lb) 

BitWalk Rate (100 ft) 

Bit Walk Angle (deg) 

Bit D 

-102.25 

-1.75 

-19.32 

Fig. 23. Bit D + PRSS performance in the Hawiyah zone. 

Fig. 21. Bit walk tendency. 

Fig. 24. Bit D + PRSS performance in the ‘Uthmaniyah zone. 

Fig. 22. Bit D + PRSS performance in the Haradh zone. 

Bit walk tendency is another comparative analytical tool 

incorporated in the DxD software. To calculate the bit walk 

tendency, the program calculates the forces in the bit cone 

area vs. the forces on the shoulder and bit gauge. 

Fundamental studies on which the DxD is based 

demonstrates that the bit walk tendency also depends on the 

drilling mode; if the bit is building or dropping, the bit walk 

tendency will change. With the point-the-bit system, the gauge 

pad and gauge cutters generate a large walk force, which 

drives bit walk to the left 3 . Figure 20 shows that both bits 

have a slight bit walk tendency to the left, as expected. Bit D 

tends to be more neutral, which reflects improvements of the 

bit design. 

Bit tool face control for Bit D also shows improvements 

because the variation of the torque on the bit is less than that 

of Bit C. The sensitivity analysis shows the same results at 

different DLS, Fig. 21. 

The field results of Bit D were optimum, and the bit was 

used in the entire Ghawar field with excellent results. The 


performances in the 12” directional section, considerably 

reducing the operator costs and significantly reducing drilling 

time. In addition to the tangible costs and time savings during 

the drilling phase, the use of the optimized 12” bit design and 

the PRSS tool have improved the hole quality by reducing the 

hole tortuosity and exposure time of the open hole, which has 

saved time in conditioning trips and running casing. 





REFERENCES 

Fig. 25. Bit D condition after completing the section in one of the Haradh wells. 

system steerability was improved, the bit cutter life extended, 

and the high vibration situations have been reduced to 

minimum values. In addition, the ROP was improved by 

25%, as compared with the previous design. To date, more 

than 20 runs have been made with Bit D which, along with 

the PRSS, have broken all previous directional drilling records 

in the 12” section in the Saudi Aramco deep gas wells. Figures 

22 to 24 show the performance of the latest bit iterations with 

the PRSS in the main three zones of the Ghawar field. Figure 

25 shows the excellent condition of Bit D after completing the 

section in one of the Haradh wells. 

CONCLUSIONS 

Teamwork, commitment to excellence, and deployment of the 

latest technologies in bits and directional tools has brought a 

step change in drilling performance in the 12” build section in 

deep gas drilling in Saudi Arabia. The combination of PRSS 

and the optimized PDC bit has delivered 13 record 

1. Shaohua Z., Al-Hajhog, J., Simpson, M.A., Luo, M., 

Mohiuddin, M. and Tan, C.: “Study of Jilh Formation 

Overpressure and its Prediction,” SPE paper 125657-MS, 

presented at the SPE/IADC Middle East Drilling 

Technology Conference and Exhibition, Manama, Bahrain, 

October 26-28, 2009. 

2. Al-Yami, H.E., Kubaisi, A.A., Nawaz, K., Awan, A., 

Verma, J. and Ganda, S.: “Powered Rotary Steerable 

Systems Offer a Step Change in Drilling Performance,” SPE 

paper 115491-MS, presented at the SPE Asia Pacific Oil 

and Gas Conference and Exhibition, Perth, Australia, 

October 20-22, 2008. 

3. Chen, S., Arfele, R. and Glass, K.: “Modeling of the Effects 

of Cutting Structure, Impact Arrestor, and Gauge 

Geometry on PDC Bit Steerability,” paper AADE-07- 

NTCE-10, presented at the AADE National Technical 

Conference and Exhibition, Houston, Texas, April 10-12, 

2007. 


BIOGRAPHIES 

Saeed H. Abdrab Al-Reda is a Gas 

Engineering Supervisor with the Gas 

Development Drilling Department 

where he has been since June 2007. 

Before joining Saudi Aramco in 

1992, he worked for a year with the 

Saudi Fertilizer Company (SAFCO) as 

a Process Engineer. Saeed has worked in various roles, 

including Senior Drilling Engineer, Drilling Engineer, 

Toolpusher, Assistant Foreman, and Drilling Foreman 

within the Drilling and Workover Department and as a Site 

Foreman for the Gas Production Department. 

In 1991, Saeed received his B.S. degree in Chemical 

Engineering from King Saud University, Riyadh, Saudi 

Arabia. 

He is the author and coauthor of five technical papers 

on Drill in Fluid (DIF) and Horizontal Drilling. 

Abdullah A. Al-Kubaisi is a Gas 

Engineering Supervisor with the Gas 

Development Drilling Department 

where he has been since June 2007. 

He joined Saudi Aramco in 

February 1991, and has worked in 

various roles including Senior Drilling 

Engineer, Drilling Engineer, Tool Pusher, Assistant Foreman 

and Drilling Foreman within the Drilling and Workover 

Department. 

In 1990, Abdullah received his B.S. degree in Petroleum 



Khalid Nawaz joined Saudi Aramco in 

2005 and currently works as a Drilling 

Engineer on a deep gas rig, and also as 

an acting Supervisor in the Gas 

Development Drilling Department. He 

has 19 years of drilling experience in 

all phases of drilling. 

Khalid received his B.E. degree in Mechanical 

Engineering from the Birla Institute of Technology, Ranchi, 

India, and went to work in drilling for the Oil and Natural 

Gas Corporation (ONGC) in India. During his 16 years 

there, he also worked in the R&D Institute and the 

technology group in Bombay Offshore. Khalid is also 

associated with and worked as an executive committee 

member with Petrotech, the Indian oil and gas conference 

and exhibition held every 2 years in India. 

Muhammad F. Jamil is presently 

supervising the Technical Department 

for Halliburton Drill Bits & Services 

(HDBS), Saudi Arabia, for one of the 

largest E&P Operations in the Middle 

East. He joined Schlumberger Wireline 

- Pakistan in 2003 as a Field Engineer, 

working there until 2003. Muhammad later joined HDBS 

as a Country Lead and then was transferred to the 

international staff with an assignment in Saudi Arabia as 

the Service Coordinator for Business Development. He 

then shifted to the Deployed Technology Group and his 

current position. 

Muhammad graduated with a B.S. degree (with Honors) 

in Engineering from the University of Engineering and 

Technology, Lahore, Pakistan in 2002. 

His main interest is in PDC product design and 

development. 

Octavio Alvarez has 14 years of 

experience in drilling operations and 

specializes in bits and coring 

technology. He has worked in various 

locations including Latin America, the 

Middle East and North Africa, and is 

currently based in Oman. Octavio is 

the Chief Applications and Design Engineer for the Middle 

East and North Africa region for Security-Halliburton. His 

related activities include drill bit and corehead design and 

applications, technical support, post-run analysis and bit 

optimization and technical training. Octavio’s interests 

include drilling operations knowledge focused on Geology, 

BHAs, downhole tools and rotational devices. 

In 1994, he received his B.S. degree in Petroleum 

Engineering from the Universidad de America, Bogota, 

Colombia. 

Baseem E. Qattawi is the Senior 

Account Representative with 

Halliburton Drill Bits & Services 

(HDBS). He joined HDBS in 2006, 

and has worked in various roles 

including application engineering and 

business development. Before joining 

HDBS, Baseem worked for three years with Kodak 

Industrial Division as a Service Engineer, then he moved on 

to work with Hatcon as a Product Manager for five years. 

In 1998, Baseem received his B.S. degree in Mechanical 

Engineering from the Philadelphia University, Amman, 

Jordan. 


Jaywant Verma is a Drilling 

Engineering Manager working with 

Schlumberger Drilling & 

Measurement. He has 21 years of 

experience in the drilling industry. 

Jaywant’s areas of expertise are 

drilling engineering and directional 

drilling. His key achievements in deep gas drilling in Saudi 

Arabia are the successful introduction of powered rotary 

steerable systems (vorteX*), the open hole sidetrack 

technique to drill challenging Khuff laterals and the 

planning and execution of medium and short radius wells. 

These techniques have helped in improving drilling 

performance and extending the frontier of drilling and 

workover operations. His areas of interest include drilling 

optimization, performance improvement and introduction 

of new technologies to provide solutions to drilling 

problems. 

Jaywant received his B.S. degree in Mechanical 

Engineering in 1986 from the University of Rajasthan, 

Jaipur, India. 

Sukesh Ganda is a Senior Drilling 

Engineer with Schlumberger, Drilling 

& Measurements with 10 years of 

petroleum industry experience. 

Currently, he is handling Saudi 

Aramco’s deep gas drilling operations 

in ‘Udhailiyah. Sukesh’s main responsibilities 

include pre-job well analysis and planning, 

monitoring and optimizing drilling execution, mentoring 

the directional drilling group, lessons learned capturing, 

and operations support. He also handles Saudi Aramco’s 

drilling related technical requirements on a day to day 

basis. Sukesh has been a key team player in the 

introduction and induction of vorteX* services in the deep 

gas environment in Saudi Arabia. 

In 1996, Sukesh received his B.S. degree in Chemical 

Engineering from T.K.I.T.E., Warananagar, India, and in 

2001 he received his M.S. degree in Petroleum Engineering 

from the New Mexico Institute of Mining and Technology, 

Socorro, NM. 


Leveraging Slim Hole Logging Tools in the 

Economic Development of Ghawar Field 

Authors: Izuchukwu Ariwodo, Ali R. Al-Belowi, Rami H. BinNasser, Robert S. Kuchinski and Ibrahim A. Zainaddin 

ABSTRACT 

Traditionally, brown field developments have often required 

the plug back and sidetrack of existing drain holes, to target 

any nearby opportunities. With advances in drilling tech - 

nology, there is a general preference to drill small diameter 

wells due to the comparative cost advantage. 

In recent times, this preference has led some wireline service 

companies to start to offer open hole formation evaluation 

services with slim tools having a diameter in the 2” to 2½” range. 

At present, most of the traditional petrophysical measurements 

can be acquired utilizing slim tools. In addition, several 

“specialized” measurements, such as cross dipole sonic, formation 

pressure testing, and resistivity imaging can also be acquired. The 

use of battery and memory technologies has allowed these tools 

to be deployed using a broader range of conveyance techniques 

allowing for reduced risk in the entry of slim hole wells. 

The provision of slim hole logging services has created an 

opportunity in the industry to leverage these tools for the 

economic development of brown fields. Therefore, short 

horizontal sidetracks and well reentries to test deeper horizons 

can be drilled and logged successfully. Saudi Aramco has been 

able to leverage these tools in its continued development of 

the giant Ghawar field. Some of the development projects are 

listed here: 

• Some horizontal sidetracks with 3 7 ⁄8” hole sizes have 

been drilled under higher doglegs than was previously 

possible, and logged successfully. 

• It is now possible to run well completions in newly 

drilled wells that have a well control problem. A 

provision is made to subsequently log these wells with 

slim wireline logging tools. 

• It is now possible to run a complete suite of wireline logs 

across some old wells that were previously completed 

without a full formation evaluation logging suite. 

• Slim hole formation resistivity imaging services are now 

being provided, to aid in the identification of borehole 

breakout and fracture features that might affect the 

well’s productivity. 

• Slim hole formation pressure testing has been acquired 

in slim hole wells to generate a pressure gradient, 

determine oil mobility, and define oil-water contacts. 

Several case studies will be used in this article to 

demonstrate how Saudi Aramco has leveraged these slim 

wireline tools to realize some development opportunities. 

Also, examples will be used to show that these slim tools do 

not compromise the quality of log data acquisition. 

INTRODUCTION 

Saudi Aramco has been producing oil and gas from its giant 

fields for over 70 years. Over this time, some of these giant 

fields have been developed to such an extent that they have 

matured into brown fields. As is done with most brown field 

development, Saudi Aramco engineers are continuously 

striving to push and extend the economic productive life of 

these fields, by the deployment of cost-effective, low risk 

technologies. 

One such cost-effective measure employed by Saudi 

Aramco engineers is the workover reentry of some existing 

producing wells, either to re-complete the next zone in the 

well, or to sidetrack and extend the well’s reach to an existing 

attic fluid elsewhere in the reservoir subsurface structure. 

Sidetracking an existing well is often challenging, as it 

requires the drilling of hole sizes smaller than the well 

diameter at the sidetracking point. As a result: 

• Because of hole size limitations, the sidetracking point is 

often determined by the expected hole size of the final 

target horizon. The well path is therefore planned from 

the total depth (TD) to the sidetrack point back to the 

motherbore. 

• Drilling bottom-hole assemblies (BHAs), which were 

generally large in diameter, do not allow for flexibility 

in building angles fast. 

• There is a high incidence of stuck pipes associated with 

attempts to drill holes smaller than 5” in diameter. 

• Special completions, like the slim smart completion 

(SSC) could not be deployed in slim holes, due to 

tubular and completion equipment size restrictions 1 . 

This problem has since been mitigated with the 

technological advancements in drilling and completion 

engineering, which has opened the scope for drilling holes 

smaller than or equal to 5”. As a result of these advance - 

ments, petroleum engineers have found a high value from the 


favorable economics of drilling smaller holes, as smaller holes 

require less drilling fluids and chemicals, cheaper casings and 

completion materials, and ultimately results in cheaper wells 

that are environmentally more efficient. 

The favorable economics of slim hole wells has subsequently 

become a value driver for the development of slim hole wireline 

and logging while drilling (LWD) technology by the service 

companies. At present, one of the service companies 

(Weatherford) has been able to deploy successfully for Saudi 

Aramco it’s suite of slim wireline tools in the diameter range of 

2” to 2½”, capable of logging a typical traditional wireline 

quad-combo made-up of density, neutron, resistivity, sonic and 

gamma ray. In addition, several “specialized” measurements, 

such as cross dipole sonic, formation pressure testing, and 

resistivity imaging can also be acquired. 

Further developments in the use of battery and memory 

technologies has allowed some of these tools to be deployed 

using a broader range of conveyance techniques, thereby 

reducing the risks associated with slim hole well entry 2 . 

THE HISTORY OF SMALL DIAMETER LOGGING TOOLS 

The use of devices to measure the petrophysical and 

geophysical properties of the subsurface began in 1927 when 

the first electrical well logging operation was performed. Since 

that time, the use of wireline conveyed logging tools has 

become a key element for several industries with a need to 

better understand the subsurface. For example, applications 

for this type of data are well documented in ground water, 

mining, petroleum, and geotechnical endeavors. 

The technologies for acquiring this data range from simple 

measurements of resistivity for ground water applications, to 

sophisticated measurements that provide an understanding of 

formation properties for the petroleum industry. Although the 

actual logging tools that perform these measurements have all 

evolved from the first instruments used in the 1920s. Their 

development has taken different paths depending on their 

industry of use. In the oil and gas industry where boreholes 

tend to be large in diameter (up to 36”) and deep (over 

30,000 ft), logging technology has tended to have a diameter 

in the range of 3” to 5”. This size allows the tools to have 

ample room to house the various components and electronics 

necessary for them to make measurements in open hole 

environments where temperatures can exceed 160 °C, and 

pressures of over 20,000 psi. In cased hole applications, 

however, smaller diameter tools have been developed for entry 

into the well through production tubing, and for production 

logging applications where flow measurements in the well 

must be made with minimal disturbance when passing the 

logging tool through the fluids being produced. 

In the mining industry, the development of logging tools 

has evolved in a somewhat different fashion because of the 

tendency for slimmer wellbores, and shallower wells primarily 

drilled to gather information about the subsurface, and not as 

a production conduit. The resulting logging technology had a 

small diameter, had open hole applications, and was designed 

to be easily transported to remote locations where the drilling 

footprint is much smaller than that of an oil field drilling 

operation. 

OPPORTUNITIES LEADING TO SMALL DIAMETER OIL 

FIELD APPLICATIONS 

For many years, the use of small diameter open hole logging 

technology was confined to the mining industry. Aside from a 

few specialized applications, the widespread use of this 

technology in oil field applications was limited due to the 

following factors: 

• Borehole characterization. Smaller diameter tools 

needed improved characterization to make accurate 

measurement in larger holes. 

• Pressure and temperature limitations. Typically, holes 

drilled for evaluating mineral deposits are relatively 

shallow, therefore the logging instrumentation did not 

need to be constructed to the higher temperature and 

pressure specifications required for oil field use. 

• Range of measurement options. The applications for 

evaluating mineral deposits from petrophysical data are 

limited compared to those for oil and gas deposits. 

Therefore, the number of measurement options was far 

fewer, leaving many gaps in the types of information that 

could be obtained from small diameter logging tools. 

In the 1980s, oil field drilling technologies began to be 

developed that allowed for the drilling of wells with increased 

deviation, horizontal wells and slimmer wells. The acceptance 

of this drilling technology and the subsequent rapid wide - 

spread use began to produce challenges in evaluating these 

wells. These challenges thereby created opportunities to 

employ new logging techniques, including the use of small 

diameter logging technologies. 

To take advantage of the opportunities posed by the new 

drilling technologies, initiatives into new research for small 

diameter logging tools began in the late 1980s. The goal of 

this research was to develop technologies that could meet the 

following requirements: 

• Produce accurate measurements in larger diameter 

boreholes (at least 12¼”). 

• Be able to operate at elevated borehole temperatures 

and pressures. 

• Produce the range of measurement options commonly 

found in oil field logging operations. 

• Be slim enough to access difficult boreholes through the 

drillpipe. 

• Constructed with a rigid length as short as possible to 

help negotiate severe doglegs and to minimize rat hole 

drilling. 


• Constructed with low weight for one person handling, 

easier pushing horizontally, and for deployment to 

remote locations. 

• Be able to operate with or without a wireline. 

• Produce accurate measurements in ultra small diameter 

boreholes (less than 3”). 

The development of the open hole logging technologies that 

could address the requirements outlined above, contributed 

greatly to another emerging branch of oil field service called 

conveyance. Conveyance is a term used to describe the 

techniques that allow for the safe and efficient deployment of 

logging tools into oil and gas wells regardless of their 

geometry, condition, or diameter. The combination of this new 

generation of small diameter logging tools and conveyance 

techniques has now made it possible to acquire open hole log 

data in situations where it was previously impossible. This 

ability has further expanded the application of ultra slim hole 

drilling in brown fields providing increased economic benefits 

for operators around the world. 

LOGGING SMALL DIAMETER WELLS 

The use of small diameter logging tools to acquire data in the 

ultra slim holes drilled in Saudi Arabia provided data that was 

previously unobtainable with conventional technology. Listed 

below is a summary of the measurement and conveyance 

options that allow for the acquisition of open hole data from 

ultra slim wells. 

Modern small diameter open hole logging tools have been 

developed to include all of the sensors necessary for making 

the basic petrophysical measurements as well as those 

required for the most common specialized measurements. A 

brief review of these tools is provided. 

Resistivity Family Array Induction 

This includes the array induction tools, which produces 

measurements of formation resistivity, and invasion profiles in 

fresh water or oil based wellbore fluids, and air filled 

boreholes. With advanced processing techniques, a 6” vertical 

resolution can be achieved. 

The Dual Laterolog (DLL) tool produces measurements of 

formation resistivity, in high contrast Rt/Rm environments. 

This tool provides individually optimized deep and shallow 

penetration curves that share a common 2 ft vertical 

resolution. 

The microresistivity tool can be configured as a micro-log 

or a micro-Laterolog device by using interchangeable pads. 

These pads can be adapted to specialized pipe conveyed 

logging operations. 

Density - Neutron Porosity Family 

Dual neutron porosity is derived using a chemical source and 

highly sensitive detectors. The tool is fully characterized for 

air and mud filled environments in both cased and open holes. 

The photo density measures both the bulk density and 

photoelectric effect of the formation in both open and cased 

holes. The chemical source and scintillation detectors are 

mounted in an articulated skid that maintains contact with the 

formation in washed out sections of the borehole. A skid plate 

profile is also adapted to maximize formation contact, 

regardless of bit size. 

Spectral Gamma Ray 

The spectral gamma ray measures and separates natural 

gamma radiation to determine the quantities of potassium, 

uranium and thorium in the formation. 

Sonic Family 

The Sonic tool measures formation compressional slowness by 

using a single sided array of transmitters and receivers. Full 

waveforms are also recorded to allow for the measurement of 

formation shear slowness. The tool can also be adapted to 

cased hole applications for evaluation of the cement bond. 

The small diameter memory cross-dipole tool combines 

monopole and cross-dipole acquisition capabilities. The tool 

can be deployed with or without a wireline, and is not 

constrained by wireline data transmission rates because 

waveform data are recorded to internal memory. This ability 

allows for the acquisition of larger quantities of acoustic data 

capable of providing more insight into the anisotropic 

properties of the formation for numerous applications 

including geophysical, petrophysical and geomechanical. 

Ultrasonic Gas Detector 

High frequency acoustic energy associated with the flow of 

gas into the wellbore can be detected with the ultrasonic gas 

detector. Gas flow is confirmed by an associated drop in 

borehole temperature, which is measured with a borehole 

temperature sub run in combination. 

Formation Pressure Tester 

The formation pressure tester utilizes a “car jack” mechanism 

to extend the pad against the borehole wall for an optimal 

seal, regardless of borehole rugosity. The tool body remains in 

the center of the borehole, thereby greatly reducing the risk of 

differential sticking. Formation pressure is measured with a 

quartz gauge for high accuracy. This tool is readily adaptable 

to holes sizes from 3” to 12¼” using interchangeable pads 

and arms. This tool can also be deployed using a number of 

conveyance techniques not possible with conventional sized 

testing tools. This allows for the acquisition of pressure data 

in difficult to log wells with a minimal risk of lost in hole. 

Figure 1 is a photo of a small diameter formation testing tool 

in the open position. 

Microresistivity Imaging Tool 

The microresistivity imaging tool is an eight arm device that 

measures high resolution formation images in water based 


orehole fluids. This tool can be configured so that its 

diameter is 2.4” or 4.1” by the installation of interchangeable 

pads. The eight arm design and the interchangeable pads 

allow the tool to acquire images in holes as slim as 3” or as 

large as 13”, and still allow for borehole coverage similar to 

larger imaging tools currently on the market. The tool can 

also be deployed using a number of conveyance techniques 

not possible with conventional sized imaging tools. Figure 2 is 

Fig. 1. A small diameter formation testing tool. 

a photo of a small diameter microresistivity imaging tool 

(2.4” version) in the open position exiting open ended 

drillpipe. 

Conveyance Options 

The modern small diameter logging tools previously described 

have been designed to obtain quality petrophysical data and also 

to be integrated into efficient deployment systems. Figure 3 

outlines the conveyance options available for small diameter tools. 

Two features of small diameter tools make them suitable 

for deployment in a wider range of scenarios than larger 

conventionally sized logging tools. These include: 

Size. With their slim design, these tools can be run in hole 

(RIH) through standard tubing, such as drillpipe (for wells 

with difficult hole conditions) and production tubing (for 

wells that have been completed), making access into 

wellbores efficient and less risky. The slim design also 

allows for access into wells as slim as 3”. With their short 

design, these tools are able to navigate wells with high 

dogleg severity, such as ultra slim sidetracks. With their 

lightweight design, these tools are easier to push with well 

tractors and coiled tubing (CT), improving the effectiveness 

of these conveyance methods. 

Low Power Requirements. This feature allows these 

logging tools to be run free of a wireline. Without a 

wireline to transmit power to the tools, the logging 

operation can be performed in several ways that will 

reduce the time required to log, and risk with respect to 

well control and equipment damage. 

The two key features described above expand the number of 

ways small diameter tools can be conveyed into a well. Listed 

below are the main conveyance techniques that are possible 

with these tools along with a brief description of the technique. 

• Wireline 3 - Widely used method of conveyance of 

logging tools by electric cables. 

Fig. 2. A small diameter microresistivity imaging tool (2.4” version). 


• Through the Bit 5 - This technique allows for logging to 

take place as quickly after drilling or coring as possible. 

In this method, small diameter logging tools are 

conveyed through the drillpipe conduit (specially 

designed drill bits with removable central inserts). 

Logging tools can be dropped off, with a wireline dropoff 

tool, and log data can be recorded in memory mode 

as drillpipe is tripped from the well. 

FIELD EXAMPLES 

Small Diameter Wireline Resistivity Imaging Examples 

Fig. 3. The conveyance options available for small diameter tools. 

• Well Shuttle 4 - This is a conveyance method where a 

string of small diameter logging tools is conveyed to TD 

inside the safety of a drillpipe garage. 

• Through Drillpipe Logging - This is a conveyance 

technique that can be used when well restrictions, 

caused by sloughing formations, ledges, and other 

obstructions, make open hole wireline conveyance 

problematic or impossible. With this technique, open 

ended drillpipe is lowered into the well below the 

zone(s) of restriction. 

• CT - This conveyance employs CT to convey small 

diameter logging tools into difficult to access wells. 

• Slick Line - Small diameter logging tools can be 

deployed on a slick line by attaching the tools directly 

to the end of the line. Deployment of the tools must be 

in memory mode and can be run on any slick line, 

regardless of provider. 

• Wireline Drop-off - This conveyance system allows for 

open hole data acquisition while tripping. In this 

technique, small diameter logging tools in memory 

mode are conveyed downhole by wireline through the 

drillpipe conduit. The logging tools pass through the 

open ended drillpipe, and hang into the open hole on a 

no-go at the bottom of the drillstring. The wireline 

drop-off system is activated by mechanical or electrical 

means, and after release, the wireline is removed from 

the well. Drillpipe is tripped from the well and log data 

is recovered from the memory sub at the surface upon 

tripping out of the hole. 

• Wireline Tractor - This conveyance is a technique where 

logging tools are conveyed into highly deviated or 

horizontal wells on wireline with the aid of tractors 

(mechanical devices powered with electricity transmitted 

through the wireline from the surface). 

The well (Well A) in Fig. 4 was a re-completion candidate. 

Well A was dead due to high water production. The recompletion 

objectives included running a slim hole imaging 

tool to help identify, characterize and isolate the fractures 

causing high water production in the well. A small diameter 

microresistivity imaging tool conveyed with a tractor was 

deployed in the well. 

The well (Well B) in Fig. 5 was a workover re-completion 

well, targeting the placement of a short radius horizontal 

sidetracked well, to target attic oil in the main reservoir. Due 

to borehole limitation, a window was cut from the 7” liner, 

and a buildup section was drilled, to the target reservoir and 

cased-off with a 4½” liner. The horizontal leg of the well was 

subsequently drilled with a 3 7 ⁄8” slim assembly. A small 

diameter logging suite made-up of a triple combo and the 

Fig. 4. Formation resistivity image from a small diameter tool (Well A). 


Fig. 6. Plot of a sidetracked (Well C) logged with small diameter triple combo tools. 

Fig. 5. Formation resistivity image from a small diameter tool (Well B). 

attached image log were successfully logged across the 3 7 ⁄8” 

horizontal section. The logging tools were conveyed on the 

end of a drillpipe in memory mode. 

Small Diameter Triple Combo Example 

The example well (Well C) in Fig. 6 was planned as a short 

radius horizontal sidetrack, targeting attic oil in the main 

reservoir. As a result of borehole limitations, a window was 

cut from the 7” liner, and the buildup section of Well C was 

drilled, to the target reservoir and cased-off with a 4½” liner. 

The horizontal leg of Well C was subsequently drilled with a 

3 7 ⁄8” slim assembly. The log data presented in Fig. 6 was 

logged with small diameter triple combo logging tools 

conveyed on the end of a drillpipe in memory mode. 

The well (Well D) in Fig. 7 was planned as a vertical 

producer. Due to pressure control problems at the time of 

drilling this well, no open hole logs could be taken. A difficult 

decision was made to RIH with production tubing and initially 

complete Well D without logging. Weatherford was sub - 

sequently invited to acquire the triple combo open hole data. 

This data was acquired in a rigless operation by conveying the 

logging tools in real time on wireline through the tubing into 

the barefoot section of the well. The log data from Fig. 7 was 

safely and efficiently acquired, and in compliance with Saudi 

Aramco’s wireline standard procedures. 

Fig. 7. Plot of a vertical well (Well D) logged with small diameter triple combo tools. 

Small Diameter Wireline Pressure Tester Example 

The well (Well E) in Figs. 8 and 9 was drilled as a slim 3 7 ⁄8” 

vertical evaluation well. Due to hole size restriction in a 3 7 ⁄8” 

hole, a small diameter formation pressure tool was run in this 

well. This tool has an outside diameter of 2.4”, and is currently 

the smallest reservoir pressure measuring device in the industry. 

The target reservoir was tight and had low mobility as 

indicated in the pressure scatter. The pressures obtained from 

this tool were sufficient to determine the reservoir pressure 

regime. The pressures agreed with the barefoot drill stem test 

that was subsequently carried out. 

CONCLUSIONS 

The drilling of slim hole wells has been shown to be a very 

effective and an economical way to access many of the brown 

field reservoirs in Saudi Arabia’s Ghawar field. The use of 

small diameter logging tools to evaluate these reservoirs has 

provided critical data necessary to make decisions on the type 

and deployment of completion hardware necessary to sustain 

production from these wells. The measurements available 


REFERENCES 

Fig. 8. Pressure drawdown profile from the small diameter tool. 

7250 

7300 

Pressure Depth 

Pressure (psia) 

3250.0 3300.0 3350.0 3400.0 3450.0 3500.0 

Extrapolated Pressure 1 

Extrapolated Pressure 2 

1. Lyngra, S., Al-Sofi, A.M., Al-Otaibi, U.F., Alshakhs, M.J. 

and Al-Alawi, A.A.: “New Technology Applications for 

Improved Attic Oil Recovery: The World’s First Slim Smart 

Completions,” IPTC paper 12365, presented at the 

International Petroleum Technology Conference, Kuala 

Lumpur, Malaysia, December 3-5, 2008. 

2. Kuchinski, R.S. and Stayton, R.J.: “Mitigating the Risks 

Associated with the Acquisition of Formation Evaluation 

Data,” paper AADE-07-NTCE-27, presented at the AADE 

National Technical Conference and Exhibition, Houston, 

Texas, April 10-12, 2007. 

3. Hilchie, D.W.: Wireline: A History of the Well Logging and 

Perforating Business in the Oil Fields, Privately Published, 

Boulder, Colorado, 1990, p. 200. 

4. Spencer, M.C., Ash, S.C. and Elkington, P.A.S.: “Pressure 

Activated Deployment of Open Hole Memory Logging 

Tools into Directional Wells and Past Bad Hole 

Conditions,” SPE paper 88635, presented at the SPE Asia 

Pacific Oil and Gas Conference and Exhibition, Perth, 

Australia, October 18-20, 2004. 

5. Runia, J., Boyes, J. and Elkington, P.: “Through Bit 

Logging: A New Method to Acquire Log Data,” SPWLA 

paper, Petrophysics, July-August 2005, Vol. 46, No. 4, pp. 

289-294. 

Depth (ft) 

7350 

7400 

7450 

7500 

7550 

Fig. 9. Well E pressure vs. depth x plot. 

from small diameter logging tools range from routine triple 

combo data to resistivity imaging and formation pressure 

data. The logging tools that acquire this data are sufficiently 

slim, short, and lightweight and can be efficiently conveyed by 

an extensive range of conveyance techniques into a wide 

variety of wellbore environments. 






BIOGRAPHIES 

Izuchukwu “Izu” Ariwodo works in 

the Reservoir Description Division as a 

Gas Development Petrophysicist. He 

started his career over 18 years ago 

when he began working as a Petroleum 

Engineer with Shell EP. While there, 

Izu also worked as an Operational 

Petrophysicist, Studies Petrophysicist and also as a Special 

Studies Geophysicist. Prior to joining Saudi Aramco in 

2006, he was the Team Leader for Petrophysics in the deepwater 

Niger Delta. 

Izu received his B.Eng. degree in Mechanical Engineering 

from the Federal University of Technology, Owerri, 

Nigeria, in 1987, and his M.S. degree in Industrial 

Engineering from the University of Ibadan, Ibadan, Western 

Nigeria, in 1990. 

Ali R. Al-Belowi is currently the 

Supervisor for the North ‘Uthmaniyah 

Unit, in the Southern Area Reservoir 

Management Department (SARMD). 

His previous posting was as Supervisor 

of the ‘Udhailiyah Area Petrophysics in 

the Reservoir Description and 

Simulation Department, where he was responsible for 

ensuring that quality production and open hole logs were 

timely analyzed, while utilizing the most accurate and 

complete petrophysics methods. Ali has done extensive 

work on petrophysics analysis in both exploration and 

development fields. 

He joined Saudi Aramco in August 1989 as a Petroleum 

Engineer after receiving his B.S. degree in Petroleum 

Engineering from King Saud University, Riyadh, Saudi 

Arabia. 

Rami H. BinNasser is a Lead 

Petrophysicist and Supervisor of the 

Special Studies Unit in the Reservoir 

Description and Simulation 

Department. As such, he sets the future 

direction for petrophysics by 

evaluating new logging and data 

processing technologies to improve formation evaluation. 

Rami has also had several assignments in the Gas & 

Exploration Unit, and as a Production Engineer and 

Reservoir Management Engineer. 

Before joining Saudi Aramco, Rami worked as a 

Wireline Logging Engineer with Schlumberger and Baker 

Atlas in the United Kingdom, India, Oman and Saudi 

Arabia. 

In 1995, Rami received his B.S. degree in Engineering 



Robert S. Kuchinski is the 

Weatherford Wireline Business 

Development Manager for the Middle 

East - North Africa region. He has 

been located in Dubai for the past 3½ 

years. Robert has been involved in the 

acquisition of subsurface data since 

1976. During this period he has worked as a Geologist in 

both the mining and petroleum businesses in Western 

Canada. In 1986 Robert joined Reeves Wireline where he 

worked in various roles including technical sales, sales 

management, and was Senior Vice President. He played a 

key role in the development of the compact technology, 

which was acquired by Weatherford in 2005. 

In 1979, Robert received his B.S. degree in Geology 

from the University of Alberta, Edmonton, Alberta, 

Canada, and in 2003 he received a certificate in Business 

Management from the University of Calgary, Calgary, 

Alberta, Canada. 

Robert is a registered professional Geologist in the 

province of Alberta, Canada. 

Ibrahim A. Zainaddin is the 

Weatherford Wireline Operation 

Manager for Saudi Arabia, Bahrain 

and Kuwait. He has been located in al- 

Khobar, Saudi Arabia, for the past 3 

years in his current role. 

In 2006, Ibrahim joined 

Weatherford Wireline as the Wireline Project Manager, 

working in technical sales and sales management. He 

played a key role in the introduction of the compact 

technology in Saudi Arabia. Ibrahim has over 14 years of 

engineering experience working for several multinational 

companies. 

In 1994, he received his B.S. degree in Applied Electrical 




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