SPE-170040-MS

Evaluation of Artificial Lift Modes for Heavy Oil Reservoirs

Prasanna Mali and Ahmad Al-Jasmi, KOC

Copyright 2014, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Heavy Oil Conference-Canada held in Alberta, Canada, 10–12 June 2014.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Exploitation of heavy oil fields in Kuwait Oil Company (KOC) has been a challenging task. Both, coldand thermal methods are planned to produce these fields judiciously. Crude oil API gravity is 10-12. Welldepth is from 700 to 3000 feet. Expected variation in production rate is from 30 - 300 bbl/d for coldproduction. With thermal application, envisaged range of liquid production rate is from 100 – 1000 bbl/d.Therefore, it is important to evaluate different artificial lift modes, to produce these heavy oil fields.

In this regard, application of various artificial lift modes, such as PCP, SRP, ESP, ESPCP, Metal PCP,etc., which can be used to produce heavy oil fields, under cold and/or thermal production pattern, arestudied and are outlined in this paper.

With regard to this feasibility study, for cold heavy oil production, pilot of conventional PCPtechnology is carried out. Liquid rates of 30 - 300 bbl/d are achieved, when PCP technology, is tested forfew wells, for cold heavy oil production. For heavy oil thermal production, pilot of ‘Metal PCP’technology is carried out, with cyclic steam injection in place. Peak liquid production rate of 460 bbl/dis achieved, when metal PCP technology is tested in one well. The paper describes pilot methodology ofthese pilots. Results of both these pilots are encouraging. This has resulted in planning to use both thesetechnologies, to produce heavy oil fields, on large scale basis.

Thus, the paper can be used as reference, to evaluate different lift technologies to produce heavy oilfields. It is inferred from the feasibility study that conventional PCP and metal PCP are emerged asdesirable lift technologies, to produce heavy oil fields. Successful pilot implementation of these technol-ogies, has further justified utility of these technologies, for exploitation of heavy oil fields.

IntroductionKuwait Oil Company (KOC) has ambitious plans to increase oil production, in years to come. As a partof this strategy, exploitation of heavy oil fields on large scale basis is being considered. It is observed thatself-flow life of wells, located in these heavy oil reservoirs, is very limited. It is, therefore, required to findsuitable and cost-effective artificial lift modes to produce these wells optimally. Both, cold heavy oilproduction and hot heavy oil production methods are being planned for exploiting heavy oil reservoirs.In view of this, present study comprises of evaluation of various artificial lift methods, which are availablefor cold heavy oil production and hot heavy oil production, with reference to reservoir and productioncharacteristics of prevailing heavy oil fields. Based on these studies, appropriate decisions are taken to

conduct pilot trials of suitable artificial lift technologies for selected candidate wells, under cold and hotconditions. The paper also outlines details of the pilots, which are carried out for selected artificial lifttechnologies for heavy oil exploitation. The study has facilitated to work-out suitable artificial lift strategyfor utilization of various artificial lift modes for effective exploitation of our heavy oil fields on large scalebasis.

Review of lift systemsIt is very crucial for any operating company to evaluate different artificial lift technologies for heavy oilexploitation, before going in for large scale field implementation. Besides, it is also prudent to carry outpilots of selected artificial lift technologies on small scale basis, in order to foresee cost-effectiveness andoperational efficiency of selected lift modes. In view of this, evaluation of different artificial lift modesand pilots of selected lift systems are carried out, with reference to our heavy oil field conditions.Representative data of heavy oil wells is given in Table - 1. Target liquid production rate of 30 - 300 bbl/dis envisaged for cold heavy oil production; while it is considered 100 – 1000 bbl/d for thermal heavy oilproduction. For testing potential of relatively deep heavy oil discoveries (with depths up to 3200 feet),cold production is conceptualized, at present. For exploitation of shallow heavy oil reservoirs (with depthsup to 1000 feet), both, cold and thermal production strategies, are planned. Cyclic steam injection isselected, as a part of thermal heavy oil recovery scheme, on a prototype scale. Maximum downholetemperature is expected to be 450°F, with cyclic steam injection in place.

In this regard, case histories and latest information supplied by reputed artificial lift technologyproviders is studied. It is observed that for heavy oil production, artificial lift technologies are evolved andmatured greatly, over a period of time. Hence, it is now possible to produce heavy oil with conventionalartificial lift systems such as Gas Lift, Hydraulic Jet Pump system, Sucker Rod Pumping (SRP) system,Electrical Submersible Pumping (ESP) system, Progressive Cavity Pumping (PCP) system, under both,cold and/or thermal production patterns. All these lift systems can work even at high temperatures of ashigh as 550°F. With latest technological advancements, enhanced flexibility in terms of rates, operationalease and run life can now also be attained; while using these lift systems to produce heavy oil.

Gas lift can be used effectively for heavy oil cold and thermal production. In gas lift, gas is injectedeither continuously or intermittently either through tubing or casing, depending on selection of productionmode. Gas lift can handle reasonable amount of sand. It is also suitable for horizontal wells. However, gaslift requires large infrastructure in terms high pressure gas compressors and injection gas line network tooperate. Thus, it requires high capital investment initially. Therefore, it is economically unviable operategas lift on small scale basis. Besides, gas lift requires committed gas source on long term basis. In viewof this, gas lift is not considered, as a preferred mode of artificial lift in KOC, for large scale field

Table 1—Comparison of Artificial Lift Modes for Heavy Oil Production

Parameters SRP ESP PCP Jet Pump ESPCP Gas Lift

Capital Cost Low High Low High Moderate High

Operating Cost Low Moderate Low High Moderate Moderate

Run life in vertical wells Average Average Average High Average High

Run life in horizontal wells Low Average Low High Average High

Ability to handle sand content Average Low Average Good Average Average

Efficiency Average Low Average Low Average Average

Suitability for thermal production Applicable Applicable Applicable Applicable Not Applicable Applicable

Operational Flexibility Average Good Good Low Average Good

Ability to handle gas content Average Good Good Good Good Good

Production Handling Capacity Good Average Good Average Average Good

2 SPE-170040-MS

implementation across all assets and hence, gas lift is not considered for implementation on pilot scale forour heavy oil cold and thermal production ventures.

ESP is essentially, a high volume lift mode. It is nothing; but a multistage centrifugal pump, which isdriven by downhole electrical motor. ESP is not typically suited for producing viscous oil. ESP is alsovery sensitive to the sand content in well-fluid stream. ESP can pose several constraints during thermalheavy oil recovery because downhole electrical components are sensitive to high temperature. Withstate-of-the-art technological developments, it is now possible to use ESP for cold and thermal heavy oilproduction and even for horizontal wells. High temperature ESPs, which can operate at 550°F, are nowalso available for thermal heavy oil recovery. However, it is observed that application of ESP for heavyoil cold and thermal production is still limited due to envisaged high capital and operating costs. Withreference to our current envisaged production rates, ESP is not considered for our heavy oil productionforay, at present.

Hydraulic Jet Pump technology uses high pressure power-fluid, which is usually water or oil.Downhole jet pump is installed inside the tubing. High pressure power-fluid is injected from surface intodownhole jet pump. Power fluid is mixed with well-fluid in downhole jet pump. Power-fluid transmitssufficient energy to the well-fluid so that well-fluid along-with power-fluid comes to the surface.Power-fluid can be sent from surface either through tubing or annulus, depending on choice of productionpattern. It is essentially, a high volume lift mode. It can be very well used for heavy oil cold and thermalproduction as well as for horizontal wells because it does not have any downhole moving parts, elastomeror electrical components. However, efficiency of jet pump is in the range of 20-30%, which is relativelymuch lower, when compared with other lift modes. Besides, it has high capital and operating costs becauseit requires elaborate surface set-up. In view of this, it is considered economically unviable for our heavyoil production plans, at present.

PCP system is also evolved as a proven and major artificial lift mode for heavy oil production globally,over the years. It is, in essence, a positive displacement pump, which is driven from surface with the helpof drive-head. Surface drive-head is operated by an electric motor and speed reducer. Downhole pumpconsists of two helical gears, which are referred, as stator and rotor. Metallic rotor is placed inside thestator. Stator is connected at the end of the tubing string and rotor is connected to the sucker rod string.Metallic rotor is placed inside the stator. Stator is stationary; while rotor is rotating inside the stator.Well-fluid is trapped in between the cavities of stator and rotor. Well-fluid moves, all along the pump axis,in the cavities existing between the rotor and stator. In case of conventional PCP, stator is made of metaland rubber elastomer is lined up all along inside of the stator. This rubber elastomer is sensitive to theprevailing well-fluid conditions and temperature. In case of metal PCP, stator is made of only metal andthere is no elastomer. This type of PCP can work even at high temperatures as high as 600°F. Various casehistories imply that use of metal PCP for high temperature application has given encouraging results forthermal heavy oil production. PCP has a smaller surface footprint. However, PCP is susceptible to thepresence of high sand content and is usually not recommended for horizontal wells due to the presenceof sucker rod string. It is examined from several case studies that conventional PCP for cold heavy oilproduction and metal PCP for thermal heavy oil recovery offer distinct advantages in terms of run life,operating range, operational flexibility, smaller surface footprint and cost of operations, within allowablelimits of given field conditions.

There is also one more variant of PCP technology, which is called as ‘Electrical Submersible PCP’(ES-PCP) system, where motion is transmitted to the rotor by downhole electric motor, which is placedbelow the downhole PCP. There is no sucker rod string. In this variant, electric cable from surface is usedfor transmitting power to the downhole motor. At present, its application is limited only to cold heavy oilproduction. It is not used for thermal heavy oil recovery because high temperature elastomer is notavailable till now. Even though, this technology is suitable for cold heavy oil production, only limitedsuccess stories are available till now due to its envisaged high capital and operating cost to produce low

SPE-170040-MS 3

to moderate heavy oil rates as well as with regard to the issues such as run life and susceptibility to handlehigh sand content.

SRP system is the oldest artificial lift mode, which is also widely used for cold and thermal heavy oilrecovery all over the world. In case of SRP operation, surface pumping unit converts rotational motion ofsurface prime mover into linear motion, as required by the downhole pump. Energy is transmitted to thedownhole reciprocating pump with the help of sucker rod string. SRPs are sensitive to the presence of sandcontent in well-fluid stream. SRPs requires larger footprint at surface. Due to the presence of sucker rodstring, SRP is generally not recommended for horizontal wells. However, SRPs offer certain benefits withregard to heavy oil production within permissible limits, in terms of operating range, run life andoperational flexibility. As regards to its capital and operating cost for heavy oil application, it is oftencomparable with PCP, for given set of operating conditions.

Table -1 shows comparison of various artificial lift modes, which are considered, for our heavy oilexploitation. It is inferred from our assessment that selection of suitable lift system for heavy oilproduction ultimately hinges on economics. Cost of acquiring and operating any particular artificial liftsystem for prevailing heavy oil production is a decisive issue because it has a direct impact to optimizeoverall cost of production operations on long term basis. It is observed from our own evaluation that thecost of procuring and managing PCP technologies, for heavy oil cold and thermal production iseconomically justified, with reference to the prevailing field conditions.

In view of our studies, pilot of conventional PCP technology is carried out for our heavy oil coldproduction; while pilot of metal PCP technology, which is designed to handle high temperature applica-tion, is carried out for producing heavy oil with cyclic steam injection in place. The paper illustrates briefdetails of these two technology pilots, which are carried out for representative wells.

PCP pilot for cold heavy oil recoveryRepresentative well data of two heavy oil reservoirs, where pilot of conventional PCP pilot technology,is carried out to produce cold heavy oil production, is given in Table - 2. For well A, PCP design is madeconsidering casing size of 9-5/8”, tubing size of 3-1/2”, perforation depth of 3050 feet, Oil API gravityof 12, GOR of 50 scf/stb and target liquid production rate of 200 bbl/d. For well B, PCP design is madeconsidering casing size of 7”, tubing size of 3-1/2”, perforation depth of around 621 feet, Oil API gravityof 12, GOR of 22 scf/stb and target liquid production rate of 400 bbl/d.

With regard to the well potential, effort is made to produce these wells with smaller capacity pumpsand that too with lower pump RPMs. Periodic monitoring with the help of echometer surveys, is carriedout in order check well-fluid level. Accordingly, pump RPMs are adjusted from time to time, to matchwith well-fluid inflow. This is required to keep sufficient pump submergence below the well-fluid level

Table 2—Representative Well Data

Design Parameters Well A Well B

Oil API 12°API 12°API

SBHP 1300 psi 188 psi

Pb 200 psi 138 psi

Target Liquid Rate 200 bbl/d 60 bbl/d (cold) / 400 bbl/d (hot)

Water cut 50% 40%

GOR 50 scf/stb 22 scf/stb

Oil Viscosity 1400 cp at 100°F 1000cp at 90° F

Bottomhole Temperature 115°F 194°F(cold) /450°F(hot)

Casing/Tubing Size 7” / 3-1/2” 7”/ 3-1/2”

Top of Perforation 3050 feet 621 feet

Pump Setting Depth 3000 feet 578 feet

4 SPE-170040-MS

so that dry running of downhole pumps, is avoided.Representative pump failures, which are reportedduring the pilot period, are described below.

Due to low productivity of wells, it is required tooptimize pump RPM from time to time, based onechometer surveys. Echo-meter surveys are carriedout at period intervals in absence of downhole sen-sors. However, in-spite of best efforts, at times, itwas not possible to avoid dry running of the pumpsin few such cases, which at times, led to the down-

hole pump failures. In case of one such instance, when pump was pulled out of the hole, it is observedthat elastomer rubber was missing along the rotor/stator lines and cracks are also observed on theelastomer. It is found that elastomer is hardened and roughened on contact surfaces of the stator. This isnormally associated with excessive heat at discharge end of the stator, where highest temperature occurs.This is observed to be a typical case of pump failure due to hysteresis phenomenon, which is normallyassociated with ‘pump-off’ conditions. In case of pump failure due to hysteresis, elastomer smells like aburnt rubber. In this case, elastomer starts to swell, especially, at pump discharge end and sudden increasein torque is observed due to excessive heat. After the complete damage of elastomer, sudden drop intorque is witnessed.

In one of the other instances, pump failure is reported due to parted polished rod. During the fishingjob, which is carried out after the pump failure, parted polished rod piece is found at a distance 62” belowthe polished rod clamp location, which is where master valve is located. When condition of the mastervalve is checked by opening and closing it for a few times, during the fishing job, it is seen that mastervalve is not actually getting fully opened from inside, even though it is apparently seen in full opencondition, when looked from outside. Thus, it is primarily concluded that parted polished rod is happened,most likely, due to continuous grinding of polished rod against the master valve, during running of thepump.

In one other instance, pump failure is reported due to the presence of high sand content, which is notenvisaged and reported before installing the pump. Sand is the main reason for sudden increase indischarge pressure of the pump because sand density has affected the fluid gradient and flow losses in thetubing, thereby, directly affecting the pump differential pressure. Elastomer swelling as well as significantcorrosion and erosion of rotor body are also observed. This is mainly attributed to the exposure of thepump to the downhole static conditions in corrosive fluid environment for a longer period.

However, barring these few instances, the pilot has given encouraging results. Oil gain, which isreported for representative wells during the pilot period, is given in Table - 3. Important lessons learntduring this pilot execution, can now be employed for large scale field implementation. Use of reliabledownhole sensors is recommended for monitoring of downhole parameters. It is crucial to carry outproduction tests for all PCP wells at periodic intervals. It is advised to use latest available production andreservoir data for PCP design as well as to optimize PCP performance periodically. It is also proposed thatoil samples of wells, where PCP is to be deployed, should be given, in order to facilitate proper selectionof elastomer. It is suggested to deploy suitable sand control technique such as slotted liner, gravel pack,etc., for PCP wells, where more than appreciable sand content is envisaged. It is expected that all thesemeasures would result in increasing run life as well as in achieving sustained oil gain; while carrying outfull scale implementation of conventional PCP technology.

PCP pilot for thermal heavy oil recoveryIn order to increase recovery from new or existing heavy oil reservoirs, thermal heavy oil recovery isimplemented successfully on full scale basis, in various heavy oil fields all over the world. Cyclic steam

Table 3—Oil Gain

Well No. Duration (days) Avg.Oil Gain (bbl/d)

A-1 166 166

A-2 134 37

B-1 47 34

B-2 67 122

B-3* 460 175

*With cyclic steam injection

SPE-170040-MS 5

injection is planned on prototype scale for one of our heavy oil fields. For our pilot with cyclic steaminjection in place, envisaged maximum temperature is 450°F. It is important to use suitable and reliableartificial lift system, which is capable to operate over wide range of reservoir and production parameters,if cyclic steam injection is planned for thermal heavy oil recovery. Conventional PCP has limitations tooperate at high temperatures because elastomer used in conventional PCP technology cannot withstandhigh operating temperatures. Therefore, use of metal PCP, which can withstand temperature of 550°F, iscontemplated. This special type of PCP does not have any elastomer. It is seen from several successfulcase histories that this type of PCP offers significant benefits in terms of capital cost, operating cost,operational ease smaller foot-print at surface, for thermal heavy oil recovery. This has led us to carry outpilot trial of this technology for representative well.

In a typical cyclic steam injection process, cyclic pumping conditions are created. In this case,operation starts with very high steam injection temperature, up to 450°F. This fluid temperature may dropalong-with time until it reaches 200°F or even less. Pump, therefore, sees from very low (below 1centipoise) to high viscosity range with wide variations in pressures. In view of this, it is essential to installappropriate lift system before injecting the steam and to keep the system safe during soaking andproduction phases.

Candidate well selected for the pilot has an oil gravity of 12°API. Well B is completed in a shallowreservoir at a depth of around 600 feet. Oil viscosity is 1000 cp at 90°F. Reservoir pressure is 188 psi andbubble point pressure is 138 psi. It is estimated that range of expected production could vary from 60 bbl/dunder cold conditions to 400 bbl/d under hot conditions, with regard to the prevailing on production andreservoir characteristics.

When metal PCP is installed, rotor is spaced out of the stator so that steam injection can be carried out.400 barrels of hot water followed by 17800 barrels of steam is introduced in 41 days. Well is left undersoaking for 18 days. The well is, then, put on production by putting rotor in the stator. The well produceda total of 86, 049 barrels of fluid with 80, 640 barrels of oil within pilot period of 460 days. Peak liquidand oil rate of 460 bbl/d and 411 bbl/d are achieved during the pilot period. Pump speed is varied from58 rpm to 210 rpm during the pilot period. As a result of continuous optimization process, it is possibleto attain pump intake pressure as low as 38 psi, during the pilot period. Steadiness in pumping efficiencyis observed from 50th day onwards; while reduction in pumping efficiency is noted after 135th day ofoperation.

With regard to the software runs with actual data, it is seen that GVF is gradually increased over aperiod of time. GVF after nearly 4 months of production is estimated at 50%; while GVF at the end ofthe pilot period is estimated at nearly 80%. Sufficient evidence of high sand content is observed; whenthe pump is pulled out at the end of the pilot period. In view of this, it is envisaged that drop in pumpingefficiency could be attributed to the high presence of free gas at pump intake and/or increased worn outof the stator and rotor, due to the presence of sand.

It can be inferred that the pilot trial of metal PCP has met with judicious success, in-spite of havingadverse conditions, which were not expected before the installation. The technology has proved itsusefulness to handle reasonable amount of sand content as well as free gas at pump intake, with minimumamount of down-time. Operational flexibility offered by the technology has allowed us to cater expecteddiversity in viscosities and temperatures of well-fluid, during the pilot period.

Pilot results have given us thorough insight about the corrective measures, to be taken up, to implementthis technology on full scale basis. Use of reliable high temperature downhole sensors is required to recordreservoir and pump data on regular basis because it is important to optimize PCP performance on regularbasis to reduce downtime. Sand control technique such as gravel pack or slotted liner is required, ifsignificant quantity of sand is expected during production. It is also advised to install the pump belowperforations, if sufficient sump space is available, in order to effect natural free gas separation to the extentpossible, before well-fluid enters into the pump intake.

6 SPE-170040-MS

ConclusionsWith regard to the evaluation of various artificial lift modes, ‘Conventional PCP’ technology and ‘MetalPCP’ technology are found suitable for cold heavy oil production and thermal heavy oil productionrespectively.

Pilots of these technologies are carried out successfully. Experience gathered during the pilot imple-mentation is certainly valuable; while going ahead with large scale field implementation of thesetechnologies for heavy oil exploitation.

It is prudent to use reliable downhole sensors to record latest reservoir and production data oncontinuous basis. It is also desirable to carry out elastomer compatibility tests before finalizing on PCPdesign. It is crucial to carry out periodic production tests for all PCP wells. Use of suitable gas handlingtools and/or sand control devices is recommended, whenever required. All these measures can help tomonitor and optimize PCP performance on regular basis.

It is inferred from the studies that optimized PCP operations is very valuable for heavy oil cold andthermal production because this would lead to accrue potential benefits in terms of enhanced PCP run life,reduced operational costs and sustained oil gain. All these issues are also crucial for managing overallcosts of heavy oil production.

AcknowledgementsAuthors are thankful to the concerned teams of KOC for providing valuable support and help during pilotconceptualization and implementation process.

ReferenceAlain-Yves HUC, Ed. Heavy Crude Oils - From Geology to Upgrading An overview, ifp Energies

Nouvelies Publications

SPE-170040-MS 7