selection and determination of tubing...

C HA P T E R

3Selection and

Determination of Tubing

and Production Casing Sizes

O U T L I N E

3.1 Overview3.2 Overview of Nodal Analysis3.3 Selection andDetermination of Tubing andProduction Casing Sizes forFlowing WellsImportance of SensitivityAnalysis of Tubing Size

Sensitivity Analysis andOptimization of TubingSize of Flowing WellOptimization MethodBased on SurfaceTubing PressureDerived by GivenSeparator Pressure

Optimization MethodBased on the GivenWellhead TubingPressure pwh

Case 1Solving ProcessCase 2Solving ProcessCase 3Solving ProcessTubing Size OptimizationMethod of EnsuringLonger Flowing Period

Case 4

Solving ProcessMethod of AnalyzingTubing Size SensitivityAffected by InflowPerformance

Case 5Solving Process

Production Casing SizeDetermination of FlowingWell

3.4 Selection andDetermination of Tubing andProduction Casing Sizes forGas WellsSelection and Determinationof Tubing Size of NaturalGas WellSelection andDetermination Methodof Tubing Size withMinimum EnergyConsumption of Liftingunder RationalProduction Rate

Case 6Solving ProcessCase 7Solving ProcessCase 8Solving Process

Method of Selecting andDetermining MaximumTubing Size underCondition of MeetingCarrying Liquid in GasWell

Case 9Solving ProcessSelection andDetermination Methodof Minimum TubingSize Avoiding Erosiondue to Excessive FlowVelocity in Gas Well


Production Casing SizeDetermination of NaturalGas Well

3.5 Selection andDetermination of Tubing andProduction Casing Sizes forArtificial Lift WellsPrediction of Daily LiquidProduction Rate Level inthe High Water Cut Period

Artificial Lift ModeDeterminationPreliminary Selection ofArtificial Lift Mode

Advanced Well Completion Engineering, Third EditionCopyright # 2011, Elsevier Inc. 117

Production ModeOptimization Using theGrade WeightedMethod

Chart Method ofSelecting OilProduction Mode

Selection and Determinationof Tubing and ProductionCasing Sizes for SuckerRod Pump WellCase 11Solving Process

Selection and Determinationof Tubing and ProductionCasing Sizes for HydraulicPiston Pump WellCase 12Solving Process

Selection and Determinationof Tubing and ProductionCasing Sizes for HydraulicJet Pump WellCase 13Solving Process

Selection and Determinationof Tubing and ProductionCasing Sizes for ElectricSubmersible Pump Well


Selection and Determinationof Tubing and ProductionCasing Sizes for Gas-LiftOil Production WellCase 15Solving Process

Selection and Determinationof Tubing and ProductionCasing Sizes for a ScrewPump Production Well

Selection and Determinationof Production Casing Sizefor Dual-String ProductionWellSelection andDetermination ofProduction Casing forDual-String Gas LiftWell

Case 16Solving ProcessSelection andDetermination ofProduction CasingSize for Other Dual-String ProductionWell

Selection andDetermination ofProduction Casing Sizefor Oil Production Wellof Electric SubmersiblePump with Y-ShapedAdapter

3.6 Effects of Stimulation onTubing and ProductionCasing Size Selection

3.7 Selection andDetermination of Tubing andProduction Casing Sizes forHeavy Oil and High Pour-Point Oil Production WellsHeavy Oil Recovery byWaterfloodingFlowing ProductionOil Production byPumping Unit and DeepWell Pump

Heavy Oil Recovery bySteam InjectionHuff and PuffHeavy Oil Recovery bySteam-Flooding

High Pour-Point CrudeProduction

References

3.1 OVERVIEW

The selection and determination of tubing andproduction casing sizes and the hole structuredesign are the important links in the well com-pletion process. The traditional practice is thatthe hole structure is designed and the productioncasing size is determined by drilling engineering.After a well completion operation, the tubingsize and the mode of production are selectedand determined by production engineering onthe basis of the production casing that has beendetermined. The result of this practice is thatthe production operations are limited by theproduction casing size, many oil and gas wellscannot adopt the adaptable technology and tech-nique, the stimulation is difficult to conduct,and the requirement of increasing the fluid

production rate of the oil well cannot beachieved at the high water cut stage. In orderto change this traditional practice, this chapterwill prove the rational selection and determina-tion of production casing size to the full extent.In accordance with the reservoir energy and therequirements of production engineering, therational tubing size should first be determinedunder a different production mode, and theadmissible minimum production casing size isthen selected and determined. At the flowingproduction stage, the rational tubing size canbe selected and determined using the sensitivityanalysis of tubing size, which is based onthe nodal analysis. At the artificial lift stage,the rational tubing size is closely related to therequirement of stable oil production during oil

118 CHAPTER 3 Selection and Determination of Tubing and Production Casing Sizes

field development and the specific lifting mode.Therefore, the nodal analysis is briefly describedat first, and the selection and determination oftubing and production casing sizes are thendescribed in detail.

The tubing and production casing sizes of oiland gas wells should be selected and determinedbefore well completion. The tubing size can bechanged, but the production casing cannotbe changed after well completion. Therefore, thetype of well, production mode, stimulation, oilproperties, and requirements of production engi-neering in the entire production process shouldbe considered when a production casing size isselected and determined; that is, natural gas wells,flowing wells, artificial lift wells, stimulation, andheavy oil production have different requirementsfor selecting tubing and production casing sizes.Thus, for a specific well, the aforementioned fac-tors should be consideredwhen the rational tubingand production casing sizes are determined.

For a natural gas well, both production opti-mization and stimulation should be consid-ered. Therefore, the tubing and productioncasing sizes should be computed as shown inEquation (3-1):

(3-1)Tubing and production casing sizes of natural

gas well ¼ max T1, T2, T3f gwhere T1 ¼ tubing and production casing sizesby production optimization; T2 ¼ tubing andproduction casing sizes by stimulation; T3 ¼tubing and production casing sizes by other spe-cial technological requirements; max ¼ maxi-mum value function.

For a conventional oil production well, thetubing and production casing sizes should becalculated as shown in Equation (3-2):

(3-2)Tubing and production casing sizes of conventional

oil production well ¼ max t1, t2, t3, t4f gwhere t1 ¼ tubing and production casing sizesat flowing stage by production optimization;t2 ¼ tubing and production casing sizes by artifi-cial lift selected; t3 ¼ tubing and production casingsizes by stimulation; t4 ¼ tubing and production

casing sizes by other special technological require-ments; and max ¼ maximum value function.

For a heavy oil production well, the tubingand production casing sizes should be calculatedas shown in Equation (3-3):

(3-3)Tubing and production casing sizes of heavy oil

production well ¼ max Tt1, Tt2, Tt3f gwhere Tt1 ¼ tubing and production casing sizesby artificial lift selected; Tt2 ¼ tubing and pro-duction casing sizes by heavy oil production;Tt3 ¼ tubing and production casing sizes by otherspecial technological requirements; max ¼ maxi-mum value function.

After the tubing and production casing sizesare determined, the casing program of a specificwell is determined in accordance with welldepth, technical requirements of drilling technol-ogy, complexity of oil and gas reservoir, andcharacteristics of overburden.

The slim hole (hole size �5 in.) completionmode includes open hole, slotted liner, and linercementing perforated completions. In addition,the monobore well completion technique hasbeen used by Shell. The slim hole completion isbasically the same as the conventional wellborecompletion, except that the matching techniquesof the slim hole, including perforating, stimula-tion, artificial lift, downhole tools, and fishingtools, should be considered in order to ensurethe normal production from a slim hole.

3.2 OVERVIEW OF NODALANALYSIS

The oil and gas flow from reservoir to surfaceseparator is shown in Figure 3-1.

The total fluid pressure loss from reservoirdeep to surface separator is composed of severalsections of pressure loss caused by resistance:pressure loss through porous media (first pres-sure subsystem), pressure loss through well com-pletion section (second pressure subsystem),total pressure loss through tubing string (thirdpressure subsystem), and total pressure lossthrough flowline (fourth pressure subsystem).

119CHAPTER 3 Selection and Determination of Tubing and Production Casing Sizes

1. Fluid pressure loss through porous mediaIn accordance with the relation between

reservoir pressure, bottomhole flowing pres-sure, oil saturation pressure, and the theoryof mechanics of fluid through porous media,the pressure distribution relations of single-phase liquid flow, single-phase gas flow,two-phase flow of oil and gas, three-phaseflow of oil, gas, and water, and dissolvedgas drive and the oil and gas inflow perfor-mance relationship can be derived; thus thetotal fluid pressure loss through porousmedia can be determined.

2. Fluid pressure loss through well completionsection

The fluid pressure loss through well comple-tion section is closely related to the well com-pletion mode and can be calculated bycalculating the total skin factor S under a differ-ent completion mode.

3. Total fluid pressure loss through tubingstring

This pressure loss can be determined bythe calculation under the multiphase flowcondition in tubing string. At present, thereare various methods to calculate multiphaseflow in pipe.

4. Total fluid pressure loss through flowlineThe same calculation method as that of

multiphase flow in pipe is used.

The oil and gas production passes through thefour subsystems in the preceding list, which canbe joined together into a unity by setting upnodes. If the analog calculation of each subsys-tem is conducted, the whole production systemcan be mathematically simulated. The nodalanalysis method uses just such an analogy calcu-lation process to analyze and optimize the pro-duction system of an oil and gas well. When aspecific problem is to be solved by using thenodal analysis method, it is usual to take aimat some node (known as the solution node) inthe system. The production system of an oil

FIGURE 3-1 Various pressure losses in the production system.


and gas well can be simplified into two largeparts (that is, inflow and outflow parts) by select-ing the solution node. For instance, when thesolution node is selected at pwf of the bottomholeof the oil well, the inflow part includes the twosubsystems, that is, the fluid flow through porousmedia and the fluid flow through completion sec-tion, while the outflow part includes the othertwo subsystems, that is, the fluid flow throughtubing string and the fluid flow through surfaceflowline. Thus, the following two major prob-lems can be solved.

1. Under the condition of constant parametervalues of the outflow part, the completionsection can be optimized using the nodal sys-tems analysis method. For instance, for aperforated well, the parameters of perforatedcompletion, including perforation density,perforation diameter, perforation length, andphase angle, can be optimized using this anal-ysis method.

2. However, under the conditions of constantcompletion mode and completion parametervalues, the tubing size and choke can be opti-mized. The sensitivity analysis of tubing size,which is described later, is just a worsening ofthis problem.

Nodal analysis of an oil and gas well not onlycan be used for solving the problem mentionedearlier, but also can be used for solving others,including determining the dynamic performanceof an oil and gas well under current productionconditions, optimizing the production restrictionfactor of an oil and gas well and presentingadaptable stimulation and adjustment measuresof an oil and gas well, determining the produc-tion state when flowing stops or is turned topumping and analyzing the reason, determiningthe optimum moment of turning to an artificiallift and its optimum mode, and finding a wayto enhance the production rate.

To sum up, for a new well, the maximumdaily fluid production and the minimum flowingpressure in the future for the entire productionprocess of the oil well should be predicted usingthe numerical simulation method or the method

of predicting the future inflow-performance rela-tionship (IPR) curve in order to optimize com-pletion parameters and tubing size using thenodal analysis method. This is what well com-pletion engineering pays the most attention to.For an oil and gas well that has been put intoproduction, the nodal analysis method is helpfulfor scientific production management.

The theory and practice of nodal analysis havebeen described in detail in the related literature.

3.3 SELECTION ANDDETERMINATION OF TUBINGAND PRODUCTION CASINGSIZES FOR FLOWING WELLS

Tubing is one of the important component partsin the production system of a flowing well and isthe main channel for oil and gas field develop-ment. The pressure drop for fluid lifting fromthe bottomhole to the surface can be up to80% of the total pressure drop of the oil andgas well system. Any oil well system has an opti-mum tubing size. Undersized tubing will limitthe production rate due to the increased frictionresistance caused by excessive flow velocity.Contrarily, oversized tubing may lead to anexcessive liquid phase loss due to slippage effector an excessive downhole liquid loading duringlifting. Therefore, sensitivity analysis of tubingsize should be carried out using the nodal analy-sis method. On the basis of the sensitivity analy-sis of tubing size, the tubing and productioncasing sizes required during the flowing periodcan be determined. However, the productioncasing size of the well cannot be determinedyet. The reason is that the tubing and productioncasing sizes of the oil and gas well should meetthe requirements of the well during the entire pro-duction life, whereas the flowing period of the oiland gas well is limited, and the tubing and pro-duction casing sizes are often on the small side.After the flowing period, the oil and gas wellmay turn to artificial lift production. The tubingand production casing sizes in the flowing pro-duction period of an oil and gas well cannot meetthe requirements of stable production in the


artificial lift production period. For a waterflood-ing oil field, after entering the high water cutperiod of the oil well, the large-size pump witha high pumping rate should often be used in orderto ensure stable oil production and rational pro-ducing pressure drawdown. For a different liftingmode, different tubing and production casingsizes should be adopted. The pump diametershould be determined in accordance with thedaily fluid production rate during the wholedevelopment period of the oil field, and thecorresponding tubing and production casing sizesare then selected. In addition, different tubingand production casing sizes are required by stim-ulation and sand control technology. Therefore,the tubing and production casing sizes can onlybe finally determined after all of the aforemen-tioned factors are taken into consideration.

By comparison with other production modes,under flowing and gas lift production modes, acertain production rate and a certain tubing shoepressure (flowing bottomhole pressure if the tub-ing shoe is in the middle of the oil reservoir)should be maintained. Under the other produc-tion modes, the flowing bottomhole pressurecan be reduced to the full extent if that isallowed by reservoir pressure and casingcondition.

Importance of Sensitivity Analysisof Tubing Size

The tubing size should be optimized in order toensure the lowest energy consumption for liftingand the longest flowing time, that is, to utilizerationally the energy of the oil and gas reservoir.

The inflow performance relationship (IPR)curve indicates the relationship in a well betweenthe flowing bottomhole pressure at a stabilizedproduction rate and the liquid production rate,which can be obtained on the basis of reservoirpressure, flowing bottomhole pressure, liquidproduction rate, and open flow rate under zeroflowing bottomhole pressure. The tubing perfor-mance relationship (TPR) curve, which isobtained on the basis of the tubing shoe pressure(flowing bottomhole pressure if the tubing shoe is

in the middle of the oil reservoir) calculated inaccordance with the flow rule (single- or two-phase flow) in tubing under the given gas-liquidratio, water cut, well depth, and wellhead pres-sure for different production rates, reflects thelifting capability of lifting tubing, which is onlydependent on tubing flow parameters, such aswellhead pressure, well depth, tubing diameter,and gas-liquid ratio, and is independent of reser-voir productivity.

Many methods of calculating the IPR canbe used, and the Vogel formula shown inEquation (3-4) is generally adopted:

(3-4)qoqoma

¼ 1� 0:2pwfpr

� 0:8pwfpr

� �2where qo is the surface production rate of the oilwell at pwf, m

3/d; qomax is the surface productionrate of the oil well at pwf ¼ 0, m3/d; pwf is theflowing bottomhole pressure, MPa; and pr isthe average reservoir pressure in the oil drainagearea, MPa.

Many methods of calculating the TPR can beused, and the Orkiszewski and Hagedom Brownmethod is generally adopted in practice.

The coordination between inflow and outflowperformances should be studied using the IPRand TPR curves in accordance with the nodalanalysis method in order to ensure the optimumutilization of natural energy.

The tubing performance relationship is shownin Figure 3-2. This figure indicates when a

FIGURE 3-2 The effect of tubing size on lifting capabilityof tubing in a flowing well.


high production rate QL>QA, 114.3-mm (4 ½ in.)tubing has the highest lifting efficiency; whenQA>QL>QB, 73-mm (2 7/8 in.) tubing is moreeconomic; and when QL<QC, 60.3-mm (2 3/8 in.)tubing is most appropriate.

Sensitivity Analysis and Optimizationof Tubing Size of Flowing Well

The fluid flow in tubing during flowing produc-tion can be analyzed in accordance with theaforementioned vertical flow rule in tubing.The most sensitive factors affecting the pressuregradient distribution of multiphase vertical flowin tubing include tubing size, production rate,gas-liquid ratio, viscosity, and water cut. For awell design, the gas-liquid ratio, viscosity, andwater cut are basically in a range, whereas theproduction rate can be controlled and changed.In accordance with the theory of multiphaseflow in tubing, each production rate value corre-sponds to the optimum tubing size so that thepressure gradient (or pressure depletion) in tub-ing can be the minimum. For a given productionrate, an undersized tubing may have an excessiveflow velocity so that the friction resistance maybe increased, whereas an oversized tubing mayhave a flow velocity on the low side so that aserious gas slippage effect may be caused. There-fore, only by selecting an appropriate tubing sizecan the friction resistance and liquid phase lossdue to slippage effect be in the optimum stateand the maximum energy utilization efficiencybe achieved.

Because the production rate is an importantparameter for optimizing and selecting the tub-ing size and the optimum tubing size is differentunder different production rates, the productionrate acts as a variable in all analyses. In the flowprocess from the reservoir to the surface, theproduction rate is closely related to the pressure,thus the pressure acts as the other variable. Theeffect of change in tubing size is often analyzedusing the coordinate diagram of pressure p andproduction rate Q. The optimum tubing size isgenerally determined using the nodal analysismethod.

There are two methods of analyzing the opti-mum tubing size. (1) Under given surface condi-tions (such as separator pressure, wellheadpressure, or surface flowline size), the tubing sizecapable of maximizing the production rate is theoptimum tubing size. (2) Under a specific produc-tion rate, the tubing size capable of minimizingthe producing gas-oil ratio, maximizing gasexpansion energy utilization efficiency, andensuring the longest flowing production time isthe optimum tubing size; that is, there are twomethods of optimizing and selecting the tubingsize or two different objective functions. In accor-dance with the specific conditions of an oil field,one of these methods can be selected or the twomethods can be used for determining the opti-mum tubing size; the optimum tubing size isfinally determined by composite consideration.The methods generally used include the optimiza-tion method based on the surface tubing pressurederived by a given separator pressure; the optimi-zation method on the basis of a given surface tub-ing pressure; and the optimization method ofensuring a relatively long flowing period.OptimizationMethod Based on Surface TubingPressure Derived by Given Separator Pressure.In order to ensure the flow from wellhead to sep-arator for the produced fluid, the minimum well-head tubing pressure pwh should be achieved onthe basis of the surface pipe network designand the specific well location. In general, theminimum entering pressure is required by enter-ing the separator. Thus the wellhead tubing pres-sure can be derived in accordance with theentering pressure, surface flowline size, path ofsurface flowline, and flow rate in the pipeline.If a choke is needed by controlling the flowingwell production, the choke pressure differentialDpchoke through the choke should be added.Thus, the wellhead tubing pressure pwh underthe minimum separator pressure can beobtained. Obviously, the pwh is related to theproduction rate Q. The higher the productionrate, the higher the minimum wellhead tubingpressure pwh required. In Figure 3-3, curve 1 isthe surface flowline and wellhead tubing pres-sure curve (no choke); curve 2 is the combined


flowline, choke, and wellhead tubing pressurecurve; and curve 3 is the remaining wellheadpressure pwh of flow from reservoir to wellheadvs. production rate curve (OPR curve), as shownin Figure 3-4.

Obviously, the changes in surface parameters(including choke size, surface flowline, and sepa-rator pressure) will change the TPR curve asshown in Figure 3-4. The changes of reservoircondition, completion mode, and tubing size(such as reservoir pressure reduction with time,different perforating parameters, and change intubing diameter) will also affect the OPR curve.

Under uncertain wellhead tubing pressure pwh,the change in tubing size is displayed by the OPRcurve. The wellhead inflow performance curvesunder the three tubing sizes and the wellhead out-flow performance curves under the two chokesizes are shown in Figure 3-5. Obviously, whenthe choke size is dch1, the tubing with diameterdt1 is the optimum production tubing; and whenthe choke size is dch2, the tubing with diameterdt3 is the optimum production tubing.Optimization Method Based on the GivenWellhead Tubing Pressure pwh. In many cir-cumstances, the conditions of surface flowlinecannot be determined in advance and the firstmethod cannot be used for the sensitivity analy-sis of tubing size. Thus, the tubing size is opti-mized by setting wellhead tubing pressure pwh.

FIGURE 3-3 The pressure system analysis using wellhead as nodeunder a given separator pressure.

FIGURE 3-4 Wellhead pressure relationship curve (OPRcurve) taking reservoir flow and tubing flow as oil wellflow system.


The inflow performance relationship (IPR)curve is first obtained. Then, in accordance withthe given wellhead tubing pressure pwh and thevarious production rates supposed, the tubingshoe pressures are calculated under differenttubing sizes. (The tubing shoe pressure is equalto the flowing bottomhole pressure pwf if thetubing shoe is in the middle of the oil reservoir.)The production rate vs. tubing shoe pressure pwf

relationship (TPR, that is, tubing performancerelationship) curves under the different tubingsizes can be obtained. Figure 3-6 shows theTPR curves under various tubing sizes. Theintersections of the TPR curves and the IPRcurve are just the production points under thevarious tubing sizes.

In general, increasing the tubing size willincrease the production rate of a flowing well.However, when the tubing size exceeds the criti-cal tubing size, the increase in tubing size maylead to a decrease in production rate, as shownin Figure 3-6.Case 1. The Shen 77 well of the Liaohe Shenyangoil field has the following known parametervalues: mean reservoir pressure pr ¼ 16.3 MPa,depth in middle of reservoir H ¼ 1673.1 m,producing gas-liquid ratio GLR ¼ 108.7 m3/m3,saturation pressure pb ¼ 18.89 MPa, relative

density of oil go ¼ 0.856, relative density of gasgg ¼ 0.73, and water cut fw ¼ 0. The IPR curveobtained with the measured production data isshown in Figure 3-7. The wellhead tubing pres-sure pwh ¼ 4.4 MPa, the wellhead temperatureTwh ¼ 20�C, and the bottomhole temperatureTwb ¼ 68�C. Try determining the optimum tubingsize under flowing production mode.Solving Process. The outflow performances ofthe various tubing sizes are calculated using theOrkiszewski method, and it is found that whenthe tubing size dt exceeds 60.3 mm (2 3/8 in.), thewell will stop flowing. Figure 3-8 shows the tub-ing outflow curve of the well. Figure 3-9 shows

FIGURE 3-5 Sensitivity analysis of tubing size underuncertain wellhead tubing pressure.

FIGURE 3-6 Sensitivity analysis of tubing size undergiven wellhead tubing pressure.

FIGURE 3-7 IPR curve of Shen 77 well.


the production rate vs. tubing size relationshipobtained by the values of the intersections ofthe IPR curve and the TPR curves. Obviously,the production rate is very sensitive to the tubingsize. When the tubing size is increased from42.2 mm (1.660 in., inside diameter 35.1 mm) to48.3 mm (1.900 in., inside diameter 40.3 mm),the production rate is obviously increased. Whenthe tubing size is further increased to 60.3 mm(2 3/8 in., inside diameter 50.7 mm), the productionrate may be greatly decreased. Thus, the optimumtubing size is 48.3 mm (1.900 in., inside diameter40.3 mm).Case 2. The Tazhong 402 well of the Talimu oilfield has the following known parameter values:mean reservoir pressure pr ¼ 42.49 MPa, depth in

middle of reservoir H ¼ 3695 m, producing gas-liquid ratio GLR ¼ 220 m3/m3, oil saturationpressure pb ¼ 42.49 MPa, relative density of oilgo ¼ 0.8331, relative density of gas gg ¼ 0.7851,and water cut fw ¼ 0. The IPR curves obtainedby matching the data of step-rate testing areshown in Figure 3-10 and indicate a high-productivity oil well. The wellhead tubing pres-sure pwh ¼ 2.0 MPa. The wellhead temperatureTwh ¼ 30�C, while the bottomhole temperatureTwb ¼ 85�C. Try determining the optimum tubingsize under flowing production mode.Solving Process. The outflow performancerelationship curves under various tubing sizes areobtained by analyzing and calculating. These -tubing sizes include 73.0 mm (2 7/8 in., internaldiameter 62 mm), 88.9 mm (3 ½ in., insidediameter 75.9 mm), 101.6 mm (4 in., inside diam-eter 90.1 mm), 114.3 mm (4 ½ in., inside diame-ter 100.5 mm), 127 mm (5 in., inside diameter115.8 mm), and 139.7 mm (5 ½ in., inside diame-ter 127.3 mm). The Q - dt curve and the pwf - dtcurve, which are obtained by the values of inter-sections of the IPR curve and the TPR curves, areshown in Figure 3-11 and Figure 3-12, respec-tively. The production rate increases with theincrease of tubing size when the tubing size issmaller than 114.3 mm (4 in.), whereas the pro-duction rate will start reducing when the tubingsize is increased to 127 mm (5 in.). Thus, theoptimum tubing size is 114.3 mm (4 ½ in.).

FIGURE 3-8 Outflow curves of Shen 77 well (obtainedby matching the measured data) under various tubingsizes (tubing sizes in figure are inside diameters).

FIGURE 3-10 Tazhong 402 well system analysis curves(tubing sizes in figure are inside diameters).

FIGURE 3-9 Production rate vs. tubing size for Shen77 well.


This example shows that a larger tubingshould be used in a high-productivity well, butan oversized tubing may reduce the productionrate by reason of slippage and increase the wellconstruction cost.Case 3. The offshore Oudna oil field in Tunisiahas the following known parameter values:original reservoir pressure pr ¼ 16 MPa, depth inmiddle of reservoir H ¼ 1600 m, producing gas-liquid ratio GLR ¼ 4.5 m3/m3, oil saturationpressure pb ¼ 1.56 MPa, relative density of oilgo ¼ 0.82, relative density of gas gg ¼ 0.76, rela-tive density of reservoir water gw ¼ 1.05, andwater cut fw ¼ 2%. The wellhead temperatureTwh ¼ 40�C and the bottomhole temperatureTwb ¼ 77.4�C. The fluid productivity index of764.6 m3/(d � MPa) is obtained by well-testing

analysis. Try determining the optimum tubingsize to achieve the production rate of 3000 m3/dunder gas lift mode when the reservoir pressureis reduced to 13 MPa. (The tubing pressure valueof 0.6 MPa is necessary for transport.)Solving Process. The gas lift performance curveunder various tubing sizes is obtained by analyz-ing and calculating as shown in Figure 3-13.When the tubing size is smaller than 168.27 mm(6 5/6 in., inside diameter 153.6 mm), the produc-tion rate increases with the increase of tubing sizeunder constant gas lift gas injection rate; andwhen the tubing size is larger than 168.27 mm(6 5/8 in., inside diameter 153.6 mm), the produc-tion rate decreases with the increase of tubingsize. The gas lift gas injection rate under produc-tion rate of 3000 m3/d (on gas lift performancecurve) vs. corresponding inside diameter of tubingis shown in Figure 3-14. In order to obtain theproduction rate of 3000 m3/d, the tubing size of168.27 mm (6 5/8 in., inside diameter 153.6 mm)needs the minimum gas lift gas injection rate andhas the highest efficiency. Thus, the optimum tub-ing size is 168.27 mm (6 5/8 in., inside diameter153.6 mm).Tubing Size OptimizationMethod of EnsuringLonger Flowing Period. Flowing oil productionis the most economic production method and theflowing period of the oil well should be pro-longed to the full extent. The key to that lies ineconomically and rationally utilizing the energy

FIGURE 3-11 Production rate vs. inside diameter oftubing for Tazhong 402 well.

FIGURE 3-12 Flowing bottomhole pressure vs. insidediameter of tubing for Tazhong 402 well.

FIGURE 3-13 Gas lift performance curves of oil well inOudna oil field under various tubing sizes (tubing sizes infigure are inside diameters).


of reservoir fluids, including the pressure energy offluid and expansion energy of gas. When the flow-ing wellhead tubing pressure is lower than the sat-uration pressure or even when the flowingbottomhole pressure is lower than the saturationpressure, the reservoir energy is mainly releasedin the form of gas expansion energy. When thegas-liquid ratio of the fluid produced from the res-ervoir is not enough, the oil well may stop flowing.

The production rate and the bottomhole pres-sure will gradually decrease in the whole flowingproduction process. The decrease in flowing bot-tomhole pressure will lead to the increase in pro-ducing gas-oil ratio, which will first rapidlyincrease on the basis of the lower initial valueand then gradually decrease to a point lowerthan the initial point. Thus, the problem ofprolonging the flowing period of the oil wellchanges into the problem of rationally utilizinggas expansion energy.

It has been believed that the tubing sizeselected should still ensure producing under themaximum lifting efficiency at the end of theflowing period. The formula of selecting tubingdiameter is shown in Equation (3-5).

(3-5)

d ¼ 0:074g1L

pwf � pwh

� �0:5 Q1L

glL� 10ðpwf � pwhÞ� �1=3

� 25:4

where d ¼ internal diameter of tubing, mm;g1 ¼ relative density of liquid; Q1 ¼ productionrate at the end of the flowing period, t/d;

L ¼ tubing length, m; pwf ¼ flowing bottomholepressure at the end of the flowing period, 105Pa;pwh ¼ flowing tubing pressure at the end of theflowing period, 105Pa.

The production rate at the end of the flowingperiod can be determined by the intersections ofthe future inflow performance IPR curve and tub-ing TPR curve. The tubing size, which can maxi-mize the current production rate, can be used forobtaining the tubing IPR curve. The intersectionsof the IPR curve and TPR curve at different stagesof drop in reservoir pressure are drawn. The tan-gential point of the IPR curve and TPR curve isjust the quit flowing point. The productionrate and the bottomhole pressure at this timeare respectively the quit flowing production rateand the quit flowing bottomhole pressure.In practice, the tubing performance curve mayalso gradually change. With continuous produc-tion, the water cut and viscosity may graduallyincrease and the gas-liquid ratio may graduallydecrease; thus the TPR curve also changes. Whenthe wellhead tubing pressure is constant, the TPRcurve may gradually move up, whereas the IPRcurve may move down, as shown in Figure 3-15.

After the quit flowing production rate andbottomhole pressure are predicted, the tubingsize that can maximize the flowing period canbe selected using Equation (3-5).

FIGURE 3-14 Inside diameter of tubing to achieve theproduction rate required vs. gas lift gas injection rate.

FIGURE 3-15 The change of production point withdecrease of reservoir pressure and the prediction of quitflowing point.


Case 4. A certain well has predictive Q1 ¼ 75 �103kg/d, minimum wellhead tubing pressurepwh ¼ 2 � 105Pa, flowing bottomhole pressurepd ¼ 23� 105Pa, well depth L ¼ 1000 m, and rel-ative density of produced fluid g1 ¼ 0.9. Try select-ing the tubing size with the longest flowing period.Solving Process. The inside diameter of thetubing is calculated using Equation (3-5).

d ¼ 0:0740:9� 1000

23� 2

� �0:5 75� 1000

0:9� 1000� 10ð23� 2Þ� �1=3

� 25:4 ¼ 58:7 mm

Tubing with an inside diameter closer to thisvalue, such as 2 7/8-in. (inside diameter 62.0 mm)tubing, can be used.Method of Analyzing Tubing Size SensitivityAffected by Inflow Performance. The princi-ples and methods of optimizing tubing size forflowing wells have been briefly described in thepreceding sections. The inflow performanceand outflow performance of a production wellare influenced and conditioned by each other.The inflow performance is the internal factorof conditioning the system, whereas the tubingitself is only an external factor. Therefore, theeffect of inflow performance change on tubingsize should be analyzed.

The reservoir pressure may reduce with theproduction time, and that may lead to inflowperformance change and gradual fluid propertychange, thus changing the tubing outflow perfor-mance and possibly changing the optimum tub-ing size. In order to simplify the analysis, theeffect of inflow performance change on the opti-mum tubing size is only discussed here.Case 5. The TuhaWenxi 1 well has the followingdata: mean reservoir pressure 24.6 MPa, depthin middle of reservoir 2513 m, producing gas-liquid ratio 116 m3/m3, oil saturation pressure18.89 MPa, relative density of oil 0.8147, relativedensity of water 1.05, relative density of gas0.824, water cut 30%, fluid productivity indexunder the flowing bottomhole pressure higherthan saturation pressure 5 m3/(d � MPa), givenwellhead tubing pressure 1.5 MPa, bottomholetemperature 79�C, and wellhead temperature

20�C. Try analyzing the change of the optimumtubing size when the reservoir pressure reducesfrom 20.6 MPa to 18.6 MPa.Solving Process. The inflow performance rela-tionships on the basis of the given data andthree different reservoir pressures are shown inFigure 3-16. The production rate vs. tubing sizeunder the different reservoir pressures isobtained on the basis of the intersections of theinflow performance curves and the tubing per-formance curves, as shown in Figure 3-17. Whenthe reservoir pressure is 24.6 MPa, the optimumtubing size is 48.3 mm (1.900 in.) or 60.3 mm(2 3/8 in.). When pr is reduced to 20.6 MPa, theproduction rate is obviously reduced, the tubinglarger than 60.3 mm (2 3/8 in.) may stop the flow-ing of the oil well, and the optimum tubingsize is changed to 48.3 mm (1.900 in.). Whenthe reservoir pressure is reduced to 18.6 MPa,the optimum tubing size is 42.2 mm (1.660 in.).

If flowing production can only be achievedusing such a small tubing, a series of problemsof production technology will certainly result(such as difficulty of paraffin removal). Thus itis better to use a larger tubing for turning to arti-ficial lift, and the economic benefit may be muchbetter. Therefore, this method can be used forpredicting the time of turning to pumping.

Production Casing SizeDetermination of Flowing Well

The tubing size should first be optimized and deter-mined on the basis of oil field development mode(waterflooding and flowing or artificial liftingproduction), oil production rate, liquid produc-tion rate, recovery rate, reservoir pressure, rule ofwater cut rising, water cut, ultimate recovery fac-tor, timing of turning to artificial lift from flowingproduction, oil properties (thin oil, heavy oil, highpour-point oil, and condensate oil), sand produc-tion situation of oil well, and stimulation. Afterthat, the maximum size of the matching downholetools (such as the maximum outside diameter ofdownhole safety valves of different specifications)should also be considered and the production cas-ing size should be finally determined.


3.4 SELECTION ANDDETERMINATION OF TUBINGAND PRODUCTION CASINGSIZES FOR GAS WELLS

Tubing size optimization of a natural gas wellshould ensure the minimum energy consumptionof lifting under rational production rate of the

gas well, and should consider the maximum tub-ing size meeting the requirement of carrying liq-uid and the minimum tubing size meeting therequirement of avoiding erosion.

Selection and Determination ofTubing Size of Natural Gas Well

SelectionandDeterminationMethodofTubingSize with Minimum Energy Consumption ofLifting under Rational Production Rate. Thetubing size of the gas well should avoid excessivepressure loss in tubing and should ensure a cer-tain tubing pressure for a longer period in orderto meet the requirement of the surface engineer-ing. The pressure loss is generally calculatedusing the gas phase conduit flow pressure dropcalculation method under different productionrates, flowing bottomhole pressures, and tubingsizes.

The inflow performance curve of a gas well isgenerally obtained using the exponential deliver-ability equation or the binomial deliverabilityequation.

FIGURE 3-16 Tubing sensitivity analysis under changing reservoir pressure.

FIGURE 3-17 Tubing size vs. production rate underdifferent reservoir pressures.


The exponential deliverability equation is asfollows

(3-6)

qg ¼ C� pr2 � pwf

2� �n

where qg ¼ daily gas production rate, 104m3/d;pr ¼ mean reservoir pressure, MPa; pwf ¼ flowingbottomhole pressure, MPa; C ¼ gas productivityindex (related to gas reservoir permeability andthickness, gas viscosity, and bottomhole clean-liness)104m3/d(MPa)�n; n ¼ filtrate index depend-ing on gas flow mode (n ¼ 1 for linear flow;n<1 for high flow velocity or multiphase flow).

The binomial deliverability equation is shownin Equation (3-7).

(3-7)pr

2 � pwf2

qg¼ Aþ Bqg

where A ¼ laminar coefficient; B ¼ turbulencecoefficient.

The A means the pressure loss induced byviscosity and the Bqg means the pressure lossinduced by inertia. The sum of both form thetotal pressure drop of inflow. When the flowvelocity is low and the flow is linear, the Bqgcan be negligible and the (pr

2�pwf2) vs. qg rela-

tionship is linear. When the flow velocityincreases or the flow is multiphase flow, the iner-tia resistance (that is, Bqg) should be considered.Case 6. A certain gas well has the following data:well depth H ¼ 3000 m, mean gas reservoir tem-perature T ¼ 50�C, relative density of gasgg ¼ 0.65, tubing wall roughness e ¼ 0.016 mm,and wellhead tubing pressure¼ 2 MPa. Try deter-mining the tubing performance curves for theinside diameters of tubing, that is, d ¼ 40.8 mm,50.7 mm, 62.0 mm, and 101.6 mm.Solving Process. The flowing bottomhole pres-sures are calculated under the various tubingsizes and the various gas production ratesQsc ¼ 1, 10, 20, 40, 60, 80 � 104m3/d in accor-dance with the flowing bottomhole pressurecalculation formula. The tubing performancecurves are shown in Figure 3-18. It is shown thatwith the increase in gas production rate the TPRcurves of smaller tubings are getting steeper

while the TPR curves of larger tubings are moregentle. The gas flow velocity and friction resis-tance increase as the tubing size decreases.Case 7. A certain water-bearing gas well hasthe following data: well depth H ¼ 3000 m,tubing size ¼ F73 mm (2 7/8 in.), relative densityof gas gg ¼ 0.65, relative density of reservoirwater gw ¼ 1.05, reservoir water viscositymw ¼ 0.8 MPa � s, and wellhead tubing pressurepwh ¼ 2 MPa. Calculate and draw the tubing per-formance curve under the various water produc-tion rates Qw ¼ 1, 10, 20, 50, 100 m3/d.Solving Process. The flowing bottomhole pres-sures are calculated using the Hagedorn-Browntwo-phase flow calculation method with progres-sive increase by 10 � 104m3 under different waterproduction rate (Qw) values, and the tubing per-formance curves of the gas well under differentwater production rates are obtained (Figure 3-19).

Figure 3-19 shows that when the gas produc-tion rate is very low, the effective density of themixture in tubing is high and the flowing bottom-hole pressure is relatively high; with an increasein gas production rate, the mixture densitydecreases and the flowing bottomhole pressuredecreases to some extent; and with a continuousincrease in gas production rate, the flow velocityincreases, the friction resistance increases, andthe flowing bottomhole pressure contrarilyincreases. When the water production rate is verylow, the effective density of the mixture is slightly

FIGURE 3-18 Tubing performance curves of pure gaswell (tubing sizes in figure are inside diameters).


affected by water and the flowing bottomholepressure has no decreasing stage, and the flowingbottomhole pressure increases with the increasein gas production rate.

The TPR curves mentioned earlier areobtained by giving tubing pressure and changingproduction rate. If a constant tubing pressure issometimes not needed, the change in tubingpressure under the coordinated condition of res-ervoir pressure and tubing flow should be deter-mined (Figure 3-20). In the figure, the ordinaterepresents pressure including reservoir pressure,flowing bottomhole pressure, and tubing pres-sure. The outflow performance relationship

(OPR) curve, known as the gas well outflowcurve, is derived on the basis of the inflow per-formance relationship (IPR) curve and the well-head tubing pressure is obtained using thegiven flowing bottomhole pressure and the tub-ing flow formula.

The IPR curve of a water-bearing gas well andthe OPR curves of different tubing sizes shownin Figure 3-20 indicate that the production ofthe gas well is controlled by choke, and thetwo straight lines A and B represent respectivelythe choke performance relationships (CPR) oftwo chokes of different sizes. In accordance withthe stability analysis, the gas well productionshould be conducted on the right side of thepeak value for each OPR curve; otherwise, apressure surge and production stoppage may becaused. When the daily gas production rate islow, a larger diameter tubing may cause gas wellproduction to stop, whereas a smaller diametertubing can maintain gas well production. Con-trarily, in a higher gas production rate range, alarger diameter tubing has a higher flow effi-ciency. Therefore, a large diameter tubing is usedin the initial gas field development period whilea small diameter tubing is adopted in the lategas field development period in order to utilizerationally the gas reservoir energy and prolongthe gas production period.

Figure 3-20 also shows that the lifting pres-sure drop of a gas well is not certain to increasewith the increase in production rate, and it has alower value at a certain critical production rate.Different tubing sizes have different gas wellproduction rates, different lifting pressure drops,and different tubing pressures. Therefore, thetubing size should be rationally selected in orderto meet the requirement of optimizingproduction.Case 8. The results of calculation of the Kelaz2 gas well are shown in Table 3-1.Solving Process. Taking the flowing bottompressure of 70 MPa as an example, the curvescan be drawn (Figure 3-21). It can be shown thatwhen the flowing bottomhole pressure is lower,the pressure loss is low and the requirement ofhigh production rate can still be met.

FIGURE 3-19 Tubing performance curves of a water-bearing gas well (the different curves in the figurecorrespond to the different water production rates).

FIGURE 3-20 Effect of tubing size on gas-well deliver-ability.


Method of Selecting and Determining Maxi-mum Tubing Size under Condition of MeetingCarrying Liquid in Gas Well.The tubing size ofthe gas well should meet the requirement ofcarrying liquid in order to avoid the downholeliquid accumulation due to slippage and theincrease in flowing bottom pressure that maycause a decrease in production rate. Thusthe maximum tubing size limit should be

determined. Generally, the following Jones Porkformula is used for calculation:

(3-8)

Qmin ¼ 35:119D2:5ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffipwf=ðMtTZÞ2

qwhere Qmin ¼ minimum allowable productionrate, 104m3/d; D ¼ inside diameter of tubing,cm; pwf ¼ flowing bottomhole pressure, MPa;Mt ¼ relative molecular mass of downholefluid; T ¼ flowing bottomhole temperature, K;Z ¼ gas deviation factor under bottomhole con-dition, dimensionless.

The maximum inside diameter of tubing vs.daily production rate curves of a gas well underthe different flowing bottomhole pressures areshown in Figure 3-22.

The maximum allowable tubing size underdifferent flowing bottomhole pressures and dif-ferent daily gas production rates can be deter-mined as shown in Figure 3-22. When thetubing size selected does not exceed the maxi-mum allowable size, the downhole liquid accu-mulation may be avoided.

TABLE 3-1 Pressure Loss in Tubing

Tubing Size[in (ID mm)]

Daily ProductionRate (104m3)

Flowing Bottom Pressure (MPa)

70 60 50 40 30 20

7 (157.07) 200 10.41 9.68 8.80 7.72 6.40 4.88300 10.79 10.10 9.27 8.27 7.11 6.01400 11.40 10.75 9.99 9.12 8.21 7.83500 12.20 11.63 10.97 9.73 9.73 10.71600 13.22 12.72 12.20 11.76 11.76 17.02700 14.43 14.05 13.70 14.46 14.46 —

51/2 (121.36) 200 11.39 10.74 9.97 9.08 8.12 7.61300 13.10 12.59 12.04 11.53 11.42 15.27400 15.58 15.30 15.13 15.32 17.39 —500 18.80 18.95 19.39 21.08 — —600 23.06 23.70 25.30 32.30 — —700 28.29 29.89 34.38 — — —

5 (108.61) 200 12.47 11.90 11.27 15.33 10.12 11.45300 15.60 15.32 15.14 23.74 17.37 —400 20.18 20.41 21.14 — — —500 26.43 27.63 30.74 — — —600 34.85 34.48 — — — —700 47.08 — — — — —

FIGURE 3-21 Pressure losses of different inside diametersof tubing under flowing bottomhole pressure of 70 MPa.


Case 9. A certain gas well has the followinginflow performance: Qg ¼ 0.3246 (13.4952�pwf

2)0.8294 (Qg: 104m3/d, p: MPa). Relative den-

sity of gas gg ¼ 0.6. Depth in middle of reservoirH ¼ 2100 m. Reservoir temperature is 80�C andwellhead temperature Twh is 25�C. The givenwellhead tubing pressure pwh is 6 MPa. Try ana-lyzing the effects of tubing sizes of 2 3/8 in.(60.3 mm, inside diameter 50.7 mm) and 3 ½in. (88.9 mm, inside diameter 75.9 mm) on thedeliverability of the system.Solving Process. First the inflow performancerelationship (IPR) curves of a gas well are drawn(Figure 3-23). Then the outflow performancerelationship (TPR) curves (TPR1 and TPR2) ofthe two tubing sizes are drawn, using the calcula-tion method of vertical tubing flow of a pure gas

well. The following results are obtained by theintersections of the IPR curve and the two TPRcurves: production rate Qg1 ¼ 15.1 � 104m3/d(pwf ¼ 8.97 MPa) when dt1 ¼ 60.3 mm (2 3/8in.); and production rate Qt2 ¼ 18.27 � 104m3/d (pwf ¼ 7.37 MPa) when dt2 ¼ 88.9 mm (3 ½in.). In this case history, the production rate ofthe system can be increased by 21.0% when thetubing size is increased from 2 3/8 in. to 3 ½ in.

The maximum allowable tubing sizes underthe different daily production rates and flowingbottomhole pressures can be calculated usingEquation (3-8) and are listed in Table 3-2.Selection and Determination Method ofMinimum Tubing Size Avoiding Erosion dueto Excessive Flow Velocity in GasWell. A seri-ous erosion may occur in the tubing of a gas well

FIGURE 3-22 Maximumallowable tubing sizemeeting requirementof carrying liquid.

FIGURE 3-23 Effects of different tubing sizes on production rates.


due to excessive flow velocity, thus leading topremature failure of the tubing. The Beggs formulais generally used for calculation.

1. Beggs erosion velocity formula, as shown inEquation (3-9):

(3-9)

Ve ¼ C

r0:5g

where Ve ¼ erosion velocity, m/s; rg ¼ gasdensity, kg/m3; C ¼ constant, dimensionless(generally 1.22; 1.5 or so under favorablecorrosion conditions).

2. Anti-erosion production rate formula, asshown in Equation (3-10):

(3-10)

Qmax ¼ 55:164� 104A

ffiffiffiffiffiffiffiffiffip

ZTgg

s

where:Qmax ¼ limiting anti-erosion productionrate, 104m3/d; A ¼ internal cross-sectional area,m2; p ¼ mean pressure in tubing, MPa;T ¼ mean temperature in tubing, K; Z ¼ gas

deviation factor under bottomhole condition,dimensionless; gg ¼ relative density of gas.

The minimum anti-erosion tubing sizes can becalculated using Equation (3-10) under differentflowing bottomhole pressures and gas productionrates as listed in Table 3-3.

The daily gas production rate vs. minimumanti-erosion tubing size can be drawn underthe different flowing bottomhole pressures (seeFigure 3-24). The minimum anti-erosion tubingsizes under different flowing bottomhole pres-sures and gas production rates are shown.Case 10. The erosion failure of tubing walland downhole tools may be caused during high-velocity gas flowing in tubing. In considerationof the effect of erosion on the tubing size selectionfor the Kela 2 gas well, the binomial deliverabilityequation is shown in Equation (3-11).

(3-11)73:892 � pwf

2

q¼ 2:4033þ 0:0034q

where q ¼ gas flow rate, 104m3/d; pwf ¼ flowingbottomhole pressure, MPa.

TABLE 3-2 Maximum Allowable Tubing Sizes Required by Carrying Liquid

FlowingPressure (MPa)

Daily Gas Production Rate (104m3/d)

50 100 150 200 250 300

70 128.9 182.3 223.3 257.8 288.3 314.2

50 138.7 196.2 240.3 277.4 310.2 325.935 140.5 198.7 243.7 281.0 314.1 342.820 155.9 220.5 270.1 311.8 348.6 381.9

TABLE 3-3 Minimum Anti-Erosion Tubing Sizes

Flowing BottomholePressure (MPa)

Daily Gas Production Rate (104m3/d)

200 300 400 500 600 700

70 83.54 102.42 118.34 132.37 145.05 156.72

60 85.33 104.62 120.89 135.23 148.20 160.1250 87.83 107.67 124.43 139.17 152.53 164.8140 91.52 112.17 129.58 144.95 158.84 171.6230 97.46 119.40 137.87 154.19 168.93 182.5020 108.00 132.11 152.46 170.42 186.65 201.59


The relative density of gas (gg) is 0.578.The relative density of gas condensate (go) is0.843. The relative density of reservoir water is1.01. The water cut is 80%. The gas-liquid ratiois 145,000 m3/m3. The depth in the middle ofthe reservoir is 3670 m. The reservoir tempera-ture is 103.5�C. The wellhead temperature is76.2�C. The tubing pressure is 55 MPa. Tryselecting the rational tubing size.Solving Process. The erosion may be caused byhigh-rate gas flowing in tubing and will be veryobvious when the flow rate exceeds a certainflow rate (erosive flow rate). Thus the through-put capacity of the gas well tubing is constrainedby the erosive flow rate. The critical anti-erosionproduction rate can be calculated in accordancewith the daily throughput capacity determinedby erosive flow rate and Equation (3-10).

The sensitivity analyses of tubing sizes of193.7 mm (7 5/8 in.), 177.8 mm (7 in.), 168.2 mm(6 5/8 in.), 139.7 mm (5 ½ in.), and 127 mm(5 in.), corresponding towhich the inside diametersare respectively 177.0 mm, 154.0 mm, 147.2 mm,124.2 mm, and 112.0 mm, are made and thecorresponding gas production rates are obtained.The corresponding erosive flow rates are calcu-lated by substituting inside diameters of tubing intoEquation (3-10). The gas production rate and ero-sive flow rate vs. tubing size curves are obtained(Figure 3-25). It is shown that the erosion will begenerated under smaller tubing. In order to avoiderosion and reduce cost to the full extent, a tubingbetween 168.2 mm (6 5/8 in.) and 177.8 mm (7 in.)is selected.

Production Casing SizeDetermination of Natural Gas Well

The production casing size selection of a naturalgas well should ensure minimum lifting frictionresistance or energy consumption under therational natural gas production rate, maximumtubing size meeting the requirement of carryingliquid, and minimum tubing size decreasing ero-sion force. In addition, the maximum size of thematching downhole tools (such as the maximumoutside diameter of downhole safety valve), thestimulations in the process of putting the wellinto production, and the measures of dewateringgas production in the late producing periodshould also be considered in order to select therational tubing size. Finally, the production cas-ing size is determined (see Table 3-4).

The outdated nominal tubing diameter is theinside diameter, while the updated or interna-tional nominal tubing diameter is the outsidediameter (see Tables 3.5 and 3.6).

3.5 SELECTION ANDDETERMINATION OF TUBINGAND PRODUCTION CASING SIZESFOR ARTIFICIAL LIFT WELLS

When the reservoir energy is insufficient or thewater cut is higher despite sufficient reservoirenergy, the artificial lift method should beused in order to maintain oil well productionunder rational producing pressure drawdown.

FIGURE 3-24 Minimum anti-erosion tubing sizes.

FIGURE 3-25 Effect of tubing ID on flow rate.


TABLE 3-4 Matching Tubing Size with Production Casing Size for Oil and Gas Wells

Outside Diameterof Tubing [mm (in.)]

Production CasingSize [mm (in.)]

Outside Diameter ofTubing [mm (in.)]

Production CasingSize [mm (in.)]

�60.3(23/8) 127(5) 127.5(5) 177.8�193.7(7�75/8)

73.0(27/8) 139.7(51/2) 139.7(51/2) 193.7(75/8)�244.5(95/8)88.9(31/2) 168.3��177.8(65/8�7) 177.8(7) 244.5(95/8)101.6(4) 177.8(7) 193.7(75/8) 273.1(103/4)114.3(41/2) 177.8(7) 244.5(95/8) 339.7(133/8)

Note: When the downhole safety valve is set, the production casing above the safety valve should be enlarged by one grade(generally 100–200 m from the surface).

TABLE 3-5 Comparison of Updated Nominal Tubing Sizes and OutdatedNominal Tubing Sizes

Nominal Diameter[mm (in.)]

Inside Diameter ofTubing (mm)

Outside Diameterof Tubing (mm)

OutdatedStandard (in.)

33.4(1.315) 26.4 33.4 1

42.2(1.660) 35.2 42.2 11/448.3(1.900) 40.3 48.3 11/260.3(23/8) 50.7 60.3 273.0(27/8) 62.0 73.0 21/288.9(31/2) 75.9 88.9 3101.6(4) 90.1 101.6 31/2

TABLE 3-6 Common Production Casing Sizes

NominalDiameter (in.)

Outside Diameterof Casing (mm) Casing Wall Thickness (mm)

41/2 114.3 5.21, 6.35, 7.37, 8.56

5 127.0 5.59, 6.43, 7.52, 9.2051/2 139.7 6.20, 6.98, 7.72, 9.17, 10.5465/8 168.3 7.32, 8.94, 10.59, 12.077 177.8 5.87, 6.91, 8.05, 9.20, 10.36, 11.51, 12.65, 13.7275/8 193.7 7.62, 8.33, 9.93, 10.92, 12.7085/8 219.2 6.71, 7.72, 8.94, 10.16, 11.43, 12.70, 14.1595/8 244.5 7.93, 8.94, 10.03, 11.05, 11.99, 13.84103/4 273.0 7.09, 8.89, 10.16, 11.43, 12.57, 13.84, 15.11, 16.51, 17.78113/4 298.9 8.46, 9.52, 11.05, 12.42133/8 339.7 8.38, 9.65, 10.92, 12.19, 13.06


Different artificial lift methods require differentmatching tubing sizes and different correspondingproduction casing sizes due to different liftingdevices and equipment and different well condi-tions. For instance, when the conventional tubingpump of F56 mm is used for oil pumping, thematching tubing size should be F73 mm (2 7/8 in.)and the maximum outside diameter of the pumpis 89.5 mm, and then the production casing ofF139.7 mm (5 ½ in.) can be selected under thesingle-string production with no sand control.If the inside casing gravel pack sand controlmethod should be used and the pump is requiredto be set at reservoir position (this factor shouldbe considered when a wire-wrapped screen sizeis selected), the production casing should belarger than F177.8 mm (7 in.). When the conven-tional tubing pump of F110 mm is used for oilpumping, the matching tubing size should beF114.3 mm (4 ½ in.), and the maximum outsidediameter of the pump is 146 mm, then the pro-duction casing size should be at leastF177.8 mm (7 in.) even if the single-string pro-duction with no sand control is adopted. If theinside casing gravel pack sand control method isrequired, the production casing of F244.5 mm(9 5/8 in.) is more adaptable.

When the tubing and production casing sizesof the artificial lift well are determined, the modeof lift should be emphatically considered. Thecommon artificial lift production modes includesucker rod pump, electric submersible pump,hydraulic piston pump, hydraulic jet pump,screw pump, and gas lift production. Sucker rodpumping accounts for more than 90% in China.The other key to determination of the type ofpump and the tubing and production casing sizesis the daily fluid production rate level in the mid-dle and late periods of waterflooding.

Prediction of Daily Liquid ProductionRate Level in the High Water CutPeriod

For a new well with adequate energy, flowingproduction can be initially adopted, but the dailyliquid production rate is relatively low because a

certain tubing shoe pressure should be main-tained. After oil well production is turned toartificial lift production during oil field water-flooding, in order to adjust the producing pres-sure drawdown, utilize reservoir potential, andachieve stable oil production, the daily fluid pro-duction rate should be gradually increased withthe increase in water cut and flowing bottom-hole pressure, thus maintaining the rationalproducing pressure drawdown.

The well completion design should be com-pleted before drilling. Thus, leadership and fore-sight should be provided for selection anddetermination of tubing and production casingsizes. The daily liquid production rate duringthe whole oil field development, especially inthe high water cut period, and the requirementsfor tubing and production casing sizes shouldbe considered.

In general, the daily liquid production rate inthe flowing period is relatively low and thecorresponding tubing and production casing sizesare also relatively small. After turning to artificiallift production, especially in the high water cutperiod, larger tubing and production casing sizesare required in order to adapt production underthe condition of a large pump. After the lift modeof the oil well is determined, the possible dailyliquid production rate in the future should be pre-dicted and the tubing and production casing sizesare then selected and determined; otherwise, theproduction rate may be limited due to the unrea-sonable strings in many oil wells. For instance, acertain well selects sucker rod pumping and theconventional tubing pump is selected. The initialdaily oil production rate is 50t/d. The water cutis 10%. The daily liquid production rate is55.6 t. If the mean pump efficiency is 60% anda tubing pump of F56 mm is selected, the match-ing tubing size is F73 mm (2 7/8 in.), the outsidediameter of the pump is 89.5 mm, and the pro-duction casing of F139.7 mm (5 ½ in.) is possi-ble. However, when the water cut of this wellfw ¼ 90%, the stable oil production rate of40t/d is required, and the daily liquid productionrate level should be at least 400 t/d. If themean pump efficiency is still 60%, the tubing


pump of F110 mm should be selected. At thistime, the tubing size matching with the pump isF114.3 mm (4 in.) and the outside diameter ofthe pump barrel is 146 mm; thus, theproduction casing should be at least F177.8 mm(7 in.). If this well is in the high water cut periodand sand control is required, the productioncasing of 7 in. cannot meet the requirement.The daily oil production rate of 40t/d cannotbe reached, and the oil production rate has to bereduced.

Therefore, the selection and determination oftubing and production casing sizes in consider-ation of the future daily production rate levelare scientific and realistic practices. After a wellis completed, the tubing size is changeable,whereas the production casing size is unchange-able. In order to discharge liquid by a large pumpin the high water cut period, a larger productioncasing size is better. Therefore, in the initial flow-ing and artificial lift period, rational tubing size isadopted on the basis of production optimization(nodal systems analysis), whereas in the highwater cut period during which a large pump isneeded for discharging the liquid, the tubing sizecan be changed to a larger tubing size.

The daily liquid production rate in the highwater cut period can be predicted in accordancewith the requirement of stable oil productiondesign. In the development program, the dailyoil production rate level (allocating oil produc-tion rate) is formulated on the basis of the reser-voir oil properties, reservoir parameters, andrequirement of allocation of oil field develop-ment. In the waterflooding oil field, the daily liq-uid production rate of the oil well should beincreased after entering into the high water cutperiod of the oil well in order to meet therequirement of stable oil production. The empir-ical method shown in Equation (3-12) is com-monly used in the field:

(3-12)

QL ¼ Qpo

1� fw

where Qpo ¼ daily allocating oil productionrate of oil well in development design, m3/d;

QL ¼ daily liquid production rate predicted,m3/d; fw ¼ water cut.

The numerical simulation method or themethod of predicting the future IPR curve shouldbe used for calculating accurately the daily liquidproduction rate in the high water cut period.

Artificial Lift Mode Determination

On the basis of the maximum tubing diameter orthe minimum production casing diameter, inaccordance with the predicted highest daily liq-uid production rate level in the high water cutperiod and the theoretical discharge capacityand discharge head calculated by supposingpump efficiency of 60%, with reference to down-hole conditions, surface environment, operationcondition, maintenance and management, andeconomic benefit, artificial lift mode is optimizedand selected. In general, artificial lift mode isselected and determined using the methodsdescribed in the following sections.Preliminary Selection of Artificial Lift Mode.Artificial lift mode is preliminarily selected inaccordance with adaptability to production con-ditions, as shown in Table 3-7.ProductionModeOptimizationUsing theGradeWeighted Method. The evaluation parametersrelated to the feasibility and complexity of vari-ous artificial lift modes are digitized, compared,and graded. The first type parameter (X) isthe parameter related to the feasibility of suc-cessful use of artificial lift mode and is dividedinto five grades (Grades 4, 3, 2, 1, and 0 representrespectively excellent feasibility, good feasibility,moderate feasibility, poor feasibility, and in-feasible). The second type parameter (Y) isthe parameter related to the method complexity,investment, and steel product consumptionand is divided into three grades (Grades 3, 2,and 1 represent respectively favorable complex-ity, moderate complexity, and unfavorable comp-lexity). X, Y, and Z are respectively calculatedusing Equations (3-13), (3-14), and (3-15), withreference to Table 3-8 and Table 3-9 under thespecific conditions of the oil well. The artificiallift methods with higher Z values are selected as


TABLE3-7

Adapta

bilityCom

pariso

nbetw

eenArtificialLiftSystem

s

Item

Adaptability

Condition

SuckerRod

Pump

Screw

Pump

Electric

Submersible

Pump

Hydraulic

PistonPump

HydraulicJet

Pump

GasLift

PlungerLift

Basicconditions

ofsystem

Degreeof

complexity

Simple

Simple

Com

plex

bottom

hole

Com

plex

surface

Com

plex

surface

Com

plex

surface

Com

plex

surface

One

investment

Low

Low

High

High

High

Highest

Highest

Operationcost

Low

Low

High

Low;Highin

high

water

cut

period

Low

Low;Highfor

smalloil

field

Low;Highfor

smalloil

field

Discharge

capacity

m3/d

Normal

range

1�100

10�2

0080�7

00300�

600

10�5

0030�3

180

20�3

2

Maximum

410

(1000)

1400

(3170)

(1293)

1590

(4769)

(7945)

63Pumpdepthm

Normal

range

3000

1500

2000

4000

2000

3000

3000

Maximum

4421

3000

3084

5486

3500

3658

3658

Dow

nhole

conditions

Slim

hole

Appropriate

Appropriate

Inappropriate

Appropriate

Appropriate

Appropriate

Appropriate

Separate-zone

production

Inappropriate

Inappropriate

Appropriate

Appropriate

Inappropriate

Appropriate

Appropriate

Directionalwell

General

wear

Serious

wear

Appropriate

Appropriate

Appropriate

Appropriate

Appropriate

Degreeof

cavitation

Strong

Strong

Strong

Strong

Strong

Strong

Strong

Surface

environm

ent

Offshoreandcity

Inappropriate

Appropriate

Appropriate

Appropriate

Appropriate

Appropriate

Appropriate

Harsh

climate

General

General

Appropriate

Appropriate

Appropriate

Appropriate

Appropriate


Operation

problems

Highgas-oilratio

Adaptable

General

Inadaptable

General

Adaptable

Veryadaptable

Veryadaptable

Heavy

oiland

high

pour-

pointoil

Good

Good

Inadaptable

Verygood

Verygood

Inadaptable

Inadaptable

Sand

production

Good

Adaptable

Inadaptable

General

General

Veryadaptable

Veryadaptable

Corrosion

Adaptable

Adaptable

Adaptable

Adaptable

Adaptable

Adaptable

Adaptable

Scaling

Adaptable

Inadaptable

Inappropriate

Adaptable

Adaptable

General

General

Working

system

adjustment

Convenient

Convenient

Lack

offlexibility

Lack

offlexibility

Convenient

Convenient

Convenient

Power

source

Electricity,natural

gas,oil

Electricity,

natural

gas,oil

Electricity

Electricity,natural

gas,oil

Electricity,natural

gas,oil

Electricity,

natural

gas,oil

Electricity,

natural

gas,oil

Requirementfor

power

media

None

None

None

Specialpower

fluid

Water

power

fluid

Avoiding

hydrate

Avoiding

hydrate

Maintenance

and

managem

ent

Pumpinspection

Pulling

outtubing

fortubing

pump

Pulling

out

tubing

Pulling

out

tubing

Hydraulicor

wire

pulling

and

running

Hydraulicor

wire

pulling

and

running

Wire

pulling

andrunning

Wire

pulling

and

running

Meanrepair-free

period(a)

21

1.5

0.5

0.5

33

Auto-control

Appropriate

General

Appropriate

Appropriate

Appropriate

General

General

Productiontest

Basically

matching

Unm

atching

Basically

matching

Basicallymatching

Unm

atching

Com

pletely

matching

Basically

matching

Notes:1.

Thedischargecapacity

values

inparentheses()meanthedischargecapacity

values

achievable

whentheexternal

diam

eter

ofproductioncasing

islarger

than

177.8mm.

2.Ifafrequencyconverterisused,theworking

system

adjustmentforvarious

artificialliftmodes

isconvenient,butthecostishigh.

3.Forthevarious

artificiallistmodes,the

flowingbottom

holepressurescanbe

reducedto

zero

undersufficient

productioncasing

strength

except

gasliftmode,underwhich

acertaintubing

shoe

pressure

(thatis,flowingbottom

hole

pressure

whentubing

issetin

themiddleof

reservoir)isrequiredin

orderto

liftthewellliquid.


TABLE 3-8 Local Feasibility Parameter Assessment Values (X)

No.Related Contentsof Local Parameter Symbol

SuckerRodPump

ElectricSubmersiblePump

HydraulicPistonPump

HydraulicJet Pump

GasLift

Surface-DrivenScrewPump

1 High production rate(>100 m3/d)

X1 2 4 2 2 4 2

2 Medium production rate(5–100 m3/d)

X2 3 4 3 3 4 3

3 Low production rate(<5 m3/d)

X3 4 1 4 4 0 4

4 High discharge head(>1350 m)

X4 1 3 4 4 4 0

5 Medium discharge head(450–1350 m)

X5 3 4 4 4 4 2

6 Low discharge head(<450 m)

X6 4 4 4 4 4 4

7 Failure-free time, rate ofwell utilization

X7 2 3 3 3 3 3

8 Well test, production test X8 3 2 2 2 4 29 Automated oil

production, parameteradjustment

X9 2 4 3 3 3 3

10 Integrity of productiontechnology

X10 2 2 3 3 3 3

11 Oil production methodefficiency

X11 1 3 3 2 2 3

12 Ability of separateproduction in a well

X12 2 2 2 2 3 2

13 Adaptability to slant anddirectional well

X13 1 3 4 4 4 3

14 Adaptability to 70�C welltemperature

X14 3 3 3 3 4 3

15 Adaptability to welltemperature higherthan 70�C

X15 2 0 3 3 4 2

16 Mechanical admixture inproduced liquid�1%

X16 2 3 2 2 4 4

17 Mechanical admixture inproduced liquid�1%

X17 0 0 0 0 3 4

18 Scaling and corrosion X18 1 1 1 1 2 219 Water cut X19 2 3 2 3 2 320 Enhanced oil recovery

abilityX20 1 4 1 1 2 2

21 High gas-oil ratio X21 2 2 2 2 4 322 High paraffin content X22 2 3 2 2 1 423 Heavy oil (<100) X23 2 1 4 4 2 424 High wellhead tubing

pressureX24 1 2 3 3 2 2

25 Harsh climate, offshore X25 1 2 3 3 2 226 Adaptability to slim hole X26 2 2 1 3 4 2


the preliminary results, and the technical and eco-nomic demonstration is then conducted in accor-dance with the technical design of a typical well,and the artificial lift mode meeting the require-ments is finally determined.

(3-13)

X ¼ n

ffiffiffiffiffiffiffiffiffiffiffiYni¼1

Xi

vuut

(3-14)

Y ¼ n

ffiffiffiffiffiffiffiffiffiffiffiYni¼1

Yi

vuut

(3-15)

Z ¼ffiffiffiffiffiffiXY

p

Chart Method of Selecting Oil ProductionMode. The two methods of selecting the oilproduction mode are as follows:

1. A rational usable range chart of suckerrod pump, electric submersible pump, and

hydraulic piston pump, which was obtainedby reference to the related charts in the late1980s and in combination with the oil fieldconditions and use experience in China, isshown in Figure 3-26. The artificial lift modecan be determined by the location of the pre-dicted coordinate point of discharge head andliquid production rate.

2. The optimum usable range charts of gaslift, plunger lift, sucker rod pump, electric

TABLE 3-9 Local Complexity Parameter Assessment Values (Y)

No.

RelatedContentsof LocalParameter Symbol

SuckerRodPump

ElectricSubmersiblePump

HydraulicPistonPump

HydraulicJet Pump

GasLift

Surface-DrivenScrewPump

1 Serviceability Y1 3 3 3 3 2 2

2 Simplicity andconvenience ofequipment

Y2 2 3 2 2 2 3

3 Energy utilizationefficiency

Y3 2 3 2 1 1 2

4 Mobility ofequipment

Y4 1 3 2 2 2 3

5 Demulsificationability

Y5 2 1 2 1 1 3

6 Degree of simplicityand ease of oilwell equipment

Y6 1 3 1 2 1 3

7 Initial investmentefficiency

Y7 2 1 2 2 2 3

8 Utilization rateof metal

Y8 1 3 1 1 1 3

FIGURE 3-26 Rational usable ranges of sucker rodpump, electric submersible pump, and hydraulic pistonpump.


submersible pump, hydraulic piston pump,and jet pump, which were presented by Blaiset al. in 1986, are shown in Figures 3-27 and3-28. The artificial lift mode can be deter-mined by the location of the coordinate pointof the predicted discharge lead and liquidproduction rate.

After artificial lift modes are determinedusing these methods, the tubing and productioncasing sizes are selected and determined on thebasis of the artificial lift modes.

Selection and Determination ofTubing and Production Casing Sizesfor Sucker Rod Pump Well

Sucker rod pumping has played a leading role inartificial lift production mode worldwide allalong. At present, sucker rod pumping has beenadopted by more than 90% of artificial lift pro-duction wells in China. Sucker rod pumps aredivided into two categories: conventional and spe-cial pumps. Special pumps include anti-sanding-inpumps, gas control pumps, heavy oil pumps, dualgassy fluid pumps, heavy oil sand control pumps,double-acting pumps, and pumps in series.

The procedure for selecting the tubing andproduction casing sizes of sucker rod pumpingwells is as follows.

1. Predicting daily liquid production rate levelin the high water cut period of an oil well.

2. Selecting theoretical discharge capacity. Thetheoretical pump discharge capacity QtL vs.daily liquid production rate QL relationshipis shown in Equation (3-16):

(3-16)

QtL ¼ QL

Zp

whereQtL ¼ theoretical pumpdischarge capac-ity, m3/d; QL ¼ daily liquid production ratepredicted, m3/d; Zp ¼ actual pump efficiency,% (generally 60% selected preliminary).

3. Selecting the nominal diameter of the pumpon the basis of theoretical discharge capacityof the pump.

4. Determining production casing size. The tub-ing size and the maximum outside diameterof the pump can be obtained on the basis ofthe nominal diameter of the pump. The pro-duction casing size matching the pump sizeis determined under the condition of gravel

FIGURE 3-27 Optimum usable ranges of plunger lift,sucker rod pump, gas lift, and electric submersible pump.

FIGURE 3-28 Optimum usable ranges of hydraulic pistonpump and hydraulic jet pump.


pack sand control well or non-sand controlwell and the condition of single-string ordual-string production.

The pump barrel of the tubing pump is at thelower end of the tubing string and the sucker rodis run in the pump barrel with the plunger. The tub-ing pump has mainly a pump barrel and plunger.Thus a relatively large pump sizewith a theoreticaldischarge capacity can be chosen. It can be used inshallow and moderately deep pumping wells withhigh productivity (Table 3-10).

The rod-insert pump has inside and outsideworking barrels and has relatively small pumpsize and discharge capacity. It is used in deepwells with low liquid levels and low productionrates (see Table 3-11).

In practice, the pumping unit cannot operateunder the maximum stroke, maximum strokesper minute, and maximum load; the fullnesscoefficient cannot be equal to 1; and the pumpefficiency cannot be equal to 100%. When thepump size is selected, pump efficiency of 50%

to 80% and (stroke) � (strokes per minute)value�36 can be preliminarily selected.

The special pumps, such as the anti-sanding-in pump, gas control pump, hydraulic feedbackheavy oil pump, circulation flow heavy oilpump, and dual gassy fluid pump, will notbe discussed in detail because they are rarelyused. However, the methods of selecting pro-duction casing size are the same as that of theconventional tubing pump and conventionalrod-insert pump.Case 11. The allocating oil production rate of acertain well on the basis of development designis 15 m3/d. The underground oil viscosity is14.5 MPa � s. The oil well has no sand produc-tion. The oil field adopts waterflooding. Tryselecting the production casing size.Solving Process. (1) The daily liquid productionrate in the high water cut period is predictedusing Equation (3-12). When the water cut fw ¼80%, QL1 ¼ 75 m3/d; when fw ¼ 90%, QL2 ¼150 m3/d; and when fw ¼ 95%, QL3 ¼ 300 m3/d.(2) The conventional tubing pump is selected.

TABLE 3-10 Matching Conventional Tubing Pump (Integral Pump Barrel)with Tubing and Production Casing

NominalDiameterof Pump(mm)

OutsideDiameter ofConnectingTubing (mm)

TheoreticalDischargeCapacity(m3/d)

MaximumOutsideDiameter (mm)

Casing Size Recommended (in.)

Non-SandControlWell

Gravel-PackSand-ControlWell

32 73.0 14�35 89.5 5�51/2 7

38 73.0 20�44 89.5 5�51/2 744 73.0 26�66 89.5 5�51/2 757 73.0 40�110 89.5 5�51/2 770 88.9 67�166 107 51/2 783 101.6 94�234 114 7 795 114.3 122�306 132.5 7 7110 114.3 164�410 146 7�95/8 95/8Plunger stroke length range: 1.2–5.0 m

Notes: 1. Under theoretical discharge capacity, lower limit strokes per minute ¼ 10/min, stroke ¼ 1.2 m; upper limit strokes perminute ¼ 6/min, stroke ¼ 5 m.2. For an inside casing gravel pack sand control well, the production casing size should be increased by one grade and a productioncasing size larger than 7 in. should be selected in order to ensure sand control effectiveness and increase thickness of gravel pack zone.For an outside gravel pack sand control well, the production casing size should be decreased by one grade. If the pump is required tobe set below the top of a perforated interval, the production casing size should be increased by one grade. Generally, the distancebetween pump and perforation should not be less than 80 m in order to protect the reservoir from surges.


Suppose the pump efficiency Zp is 80% when thewater cut is high. The theoretical dischargecapacities of the pump under the water cuts of80%, 90%, and 95% are 93.8 m3/d, 187.5 m3/d,and 375 m3/d, respectively, in accordance withEquation (3-16). In order to ensure the stableoil production rate of 15 m3/d in the high watercut period, the pump of F110 mm with a theo-retical discharge capacity of 164–410 m3/d canbe selected using Table 3-10. The tubing ofF114.3 mm (4 ½ in.) and the maximum pumpOD of 146 mm can also be selected. The produc-tion casing of F177.8 mm (7 in.) should beselected. The calculation results show the pumpsize required when the ultimate liquid productionrate is reached. Thus the tubing and productioncasing sizes can be derived. When the well is com-pleted, whether the sucker rod pump or electricsubmersible pump is adopted should be consid-ered, and then the tubing and production casingsizes are selected and the economization and effec-tiveness of both types of pumps are compared.

Selection and Determination ofTubing and Production Casing Sizesfor Hydraulic Piston Pump Well

A hydraulic piston pump has a wide dischargecapacity range (30–1274 m3/d) and is adaptableto mid-viscosity oil, high pour-point oil, anddeep pumping conditions; thus it has becomean important component part of artificial liftproduction technology in China. The adaptabil-ity and the technological conditions are shownin Table 3-12.

The common hydraulic piston pumps in-clude a single-acting pump with variable pres-sure ratio, balanced single-acting pump, long-stroke double-acting pump, and dual hydraulicmotor double-acting pump. The power fluidcirculation and tubing string assembly areshown in Table 3-13.

The selection procedures of tubing and pro-duction casing sizes of a hydraulic piston pumpare similar to that of a sucker rod pump andare as follows.

TABLE 3-11 Matching of Conventional Rod-Insert Pump with TubingAnd Production Casing

NominalDiameterof Pump(mm)

OutsideDiameter ofConnectingTubing[mm (in.)]

TheoreticalDischargeCapacity(m3/d)

MaximumOutsideDiameter(mm)

Casing Size Recommended (in)

SandControlWell

Non-SandControl Well withGravel Pack

32 60.3(23/8) 14�35 89.5 5�51/2 7

38 73.0(27/8) 20�49 89.5 5�51/2 744 73.0(27/8) 26�66 89.5 5�51/2 751 73.0(27/8) 35�88 107 51/2 756 88.9(31/2) 43�106 107 51/2 757 88.9(31/2) 44�110 107 51/2 763 88.9(31/2) 54�135 114 7 7Plunger stroke length range: 1.2–5.0 m

Notes: 1. Under theoretical discharge capacity, lower limit strokes per minute ¼ 10/min, stroke ¼ 1.2 m; upper limit strokes perminute ¼ 6/min, stroke ¼ 5 m.2. For an inside casing gravel pack sand control well, the production casing size should be increased by one grade and a productioncasing size larger than 7 in. should be selected in order to ensure sand control effectiveness and increase thickness of gravel pack zone.For an outside gravel pack sand control well, the production casing size should be decreased by one grade. If the pump is required tobe set below the top of a perforated interval, the production casing size should be increased by one grade. Generally, the distancebetween pump and perforation should not be less than 80 m in order to protect the reservoir from surges.


1. Predict the daily liquid production rate in thelate development period.

2. Select and determine the theoretical dischargecapacity QtL of the pump.

3. Find the matching tubing size and maximumoutside diameter of the pump in the technicalparameter table of a hydraulic piston pump.

Then determine the production casing sizein accordance with single-string productionor dual-string production.

The long-stroke double-acting hydraulic pis-ton pump is the most common hydraulic pistonpump and is appropriate to the oil pumping of

TABLE 3-13 Power Fluid Circulation and Tubing String Assembly

Outside Diameterof ProductionCasing [mm (in.)]

Outside Diameters of Tubing Strings Assembled [mm (in.)]

Open SingleString

Dual ParallelString

Dual ConcentricString

127(5) 60.3(23/8)73.0(27/8)

— —

140(51/2) 60.3(23/8)73.0(27/8)88.9(31/2)

60.3�33.4(23/8�1.315)

73.0�48.3(27/8�1.900)88.9�48.3(31/2�1.900)

178(7) 60.3(23/8)73.0(27/8)88.9(31/2)101.6(4)114.3(41/2)

60.3�60.3(23/8�23/8)73.0�40.3(27/8�1.900)

73.0�48.3(27/8�1.900)88.9�48.3(31/3�1.900)101.6�60.3(4�23/8)114.3�73.0(41/2�27/8)

TABLE 3-12 Adaptability and Technological Conditions of Hydraulic Piston Pump

Item Adaptability Application Ranges or Technological Conditions

Lift height Strong Normal range 3500 m, up to 5486 m

Liquid production rate Wide range Up to more than 600 m3/d for oil well with casing of F140 mm (5 1/2 in.);up to more than 1000 m3/d for oil well with casing of F178 mm (7 in.)

High gas-liquid ratio Conditionaladaptation

No limitation if gas flows out through separate passage. A certainsubmergence is required if gas is produced through pump.

Borehole deviation orbending

Strong Deviation angle of about 45�

Scaling Moderatelystrong

Anti-scaling additive is carried by power fluid, or magnetic anti-scaler isused.

Sand production Poor Sand content of power fluid should be lower than 0.01%.High pour-point oil well Strong Flow rate and temperature of power fluid should be ensured.Heavy oil well Moderately

strongThin crude oil or water base power fluid should be used and flow rate and

temperature should be ensured.Corrosion Moderately

strongCorrosion inhibitor should be carried by power fluid.

Selective zone production Strong Pump and tubing string appropriate to selective zone production are used.


the oil well with high productivity and a highliquid production rate. Matching the pumpwith tubing and production casing is shown inTable 3-14.Case 12. On the basis of the parameters ofCase 11, try selecting the tubing and productioncasing sizes of a hydraulic piston pump well.Solving Process. By calculating as Case 11,when the water cut is 95%, the daily liquid pro-duction rate is up to 300 m3/d in order to ensurethe stable oil production rate of 15 m3/d. Whenthe long-stroke double-acting hydraulic pistonpump is adopted, at least the �HB 3.0 � 50/20pump should be selected. Its theoretical dis-charge capacity is 500 m3/d (by taking the pumpefficiency of 80%, the actual discharge capacitycan be up to 400 m3/d). The outside diameterof tubing is 76.2 mm (3 in.) and the productioncasing size is F139.7 mm (5 ½ in.).

Selection and Determination ofTubing and Production Casing Sizesfor Hydraulic Jet Pump Well

A main feature of a hydraulic jet pump is thatthere is no moving component and water canbe used as the power fluid. The other surfaceequipment and downhole working barrel arethe same as that of a hydraulic piston pump.The discharge capacity can be up to 4769 m3/dand is second only to that of gas lift. The dis-charge head can be up to 3500 m and is second

only to that of a hydraulic piston pump. How-ever, the pump efficiency is relatively low andthe maximum pump efficiency is only up to32%. The hydraulic jet pump can be used foroil pumping production and is appropriate espe-cially to the high pour-point oil production andthe oil production in the high water cut period,during which the hydraulic piston pump can bereplaced by the hydraulic jet pump. The hydrau-lic jet pump is also appropriate for formationtests, drillstem tests, blocking removal, spentacid removal, and scavenging, due to its simplestructure and strong adaptability.

The selection procedures of tubing and pro-duction casing sizes of hydraulic jet pump wellsare as follows.

1. The maximum daily liquid production ratein the high water cut period is predicted usingthe aforementioned method of predicting thedaily liquid production rate level in the highwater cut period.

2. The lifting rate H is calculated as shown inEquation (3-17).

(3-17)

H ¼ p3 � p4p1 � p3

where H ¼ lifting rate; p1 ¼ working pressureat nozzle inlet, MPa (pump depth multipliedby power fluid pressure gradient plus well-head pressure of the system); p3 ¼ dischargepressure of mixed liquid, MPa (pump depth

TABLE 3-14 Matching of Long-Stroke Double-Acting Hydraulic Piston Pump with Tubingand Production Casing

Model Number of Pump SHB2.5�10/20 SHB2.5�20/20 SHB2.5�30/20 SHB3.0�50/20

Tubing size [mm (in.)] 73.0(27/8) 73.0(27/8) 73.0(27/8) 88.9(31/2)

Discharge capacity (m3/d) 100 200 300 500Maximum outside diameter (mm) 114(102) 114(102) 114 114Recommended

nominaldiameterof productioncasing

Single-stringproduction

139.7 mm,127 mm(51/2, 5 in.)

139.7 mm,127 mm(51/2, 5 in.)

139.7 mm(51/2 in.)

139.7 mm(51/2 in.)

Dual-stringproduction

177.8 mm(7 in.)

177.8 mm(7 in.)

177.8 mm(7 in.)

193.7�244.5 mm(75/8�95/8 in.)


multiplied by mixed liquid pressure gradientplus wellhead backpressure); p4 ¼ suctionpressure, MPa (submergence multiplied bycrude oil pressure gradient).

3. The jetting rate and area ratio are determinedin accordance with the empirical values inTable 3-15.

4. The maximum power fluid flow rate isobtained by the theoretical pump dischargecapacity divided by the jetting rate minimum.

5. The nozzle diameter is estimated using Equa-tion (3-18):

(3-18)

d1 ¼ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi

Qe

9:6� 107affiffiffiffiffiffiffiffiffiffiffiffiffiffiffip1 � p4

r

rvuuut

where d1 ¼ nozzle diameter, m; Qe ¼ powerfluid flow rate, m3/d; a ¼ flow rate coefficientdetermined by testing results (a ¼ 3.1 whenpower fluid is water and a ¼ 8.5 when power

fluid is heavy oil); r ¼ power fluid density,kg/m3.

6. Throat diameter is predicted using the follow-ing formula:

(3-19)

d2 ¼ffiffiffiffiffiffiffid1

2

R

s

where d2 ¼ throat diameter, mm; R ¼ arearate (see Table 3-15).

7. The tubing and production casing sizes aredetermined on the basis of nozzle diameterand throat diameter in accordance withTable 3-16 and the type of pump selected.

Case 13. In accordance with the developmentprogram of a certain well, the allocating oilproduction rate in the late period is 7 m3/d, theworking pressure at the nozzle inlet is26.7 MPa, the suction pressure is 12.1 MPa, andthe discharge pressure of mixed liquid is17.0 MPa. The water base power fluid isadopted. Try selecting the production casing size.Solving Process1. On the basis of the allocating oil production

rate of 7 m3/d and the predicted water cutof 95%, the maximum daily liquid produc-tion rate of 139 m3/d is predicted in accor-dance with Equation (3-12).

2. The lifting rate H is calculated as follows.

H ¼ 17:0� 12:1

26:7� 17:0¼ 0:51

TABLE 3-15 Empirical Values ofKey Parameters

Lifting Rate H Jetting Rate M Area Ratio R

<>0.15 >1.5 0.17

0.15�0.25 1.5�1.0 0.210.25�0.3 1.0�0.7 0.260.3�0.45 0.7�0.5 0.330.45�0.8 0.5�0.1 0.41

TABLE 3-16 Matching of Conventional Jet Pump with Tubing and Production Casing

Index

Type of Jet Pump

SPB 2.5 SeriesCasing-TypeJet Pump

Up-Jet-TypeJet Pump

F62 mm Short-Type Jet Pump

Nozzle diameter 1.9�6.0 2.1�3.9 1,8�6.8 1.8�6.8

Throat diameter 4.5�9.8 3.3�6.2 2.9�11.0 2.9�11.0Tubing OD 73 73 60.3 73Maximum OD of pump 114 114 89 114Minimum ID of casing 127(51/2 in.) 127(51/2 in.) 100(41/2 in.) 127(51/2 in.)

Note: The power fluid of a casing-type jet pump flows in from casing and the mixed liquid flows out through tubing.


3. The jetting rate of 0.5 and the area ratio of0.41 are obtained using Table 3-15.

4. The power fluid flow rate Qe is predicted asfollows.

Qe ¼ 139

0:5¼ 278 m3=d

5. The nozzle diameter is predicted usingEquation (3-18).

d1 ¼ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi

278

9:6� 107 � 3:1

ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi26:7� 12:1

1000

rvuuut � 0:0028 m

¼ 2:8 mm

6. The throat diameter is predicted usingEquation (3-19).

d2 ¼ffiffiffiffiffiffiffiffiffi2:82

0:41

s¼ 4:4 mm

7. On the basis of the nozzle diameter and thethroat diameter, the short-type jet pump ofF62 mm is selected, and the maximum pumpOD of 114 mm and the minimum productioncasing ID of 127 mm are obtained. Thus theproduction casing of F139.7 mm (5 ½ in.)or F177.8 mm (7 in.) should be selected.

Selection and Determination ofTubing and Production CasingSizes for Electric SubmersiblePump Well

The electric submersible pump is adaptable to oilwells (including directional wells) of high dis-charge capacity, low and medium viscosity oil,low sand content, and pump depth less than2500 m. The electric submersible pump can alsobe used in the gravel pack sand control well underthe conventional production condition of heavyoil. At present, the theoretical discharge capacityof the electric submersible pump adaptable to theproduction casing of F139.7 mm (5 ½ in.) can beup to 550 m3/d. Therefore, the selection proce-dures of tubing and production casing sizes ofelectric submersible pump wells are same as thatof a hydraulic piston pump.Matching the electric

submersible pump with tubing and productioncasing is shown in Table 3-17.

Matching the TRW Reda Pumps electric sub-mersible pump with tubing and production cas-ing is shown in Table 3-18.Case 14. On the basis of the parameters ofCase 12, try selecting the production casing sizeof the electric piston pump well.Solving Process. By calculation similar toCase 11, in order to ensure the daily oil produc-tion rate of 15 m3/d under the water cut of95%, the daily liquid production rate of300 m3/d is required. In accordance withTable 3-17, the QYB120-425 pump with theoret-ical discharge capacity of 425 m3/d can be used.By taking the pump efficiency of 80%, the actualdischarge capacity can be up to 340 m3/d, whichcan meet the requirement of daily liquid produc-tion rate of 300 m3/d. The corresponding tubingsize of F73 mm (2 7/8 in.) can be selected. For aconventional well with no sand control, the pro-duction casing size of F139.7 mm (5 ½ in.) isselected. For the gravel pack sand control well,the production casing of F177.8 mm (7 in.) canbe selected in order to ensure sand control effec-tiveness by increasing the thickness of the gravelpack sand control zone. If a larger dischargecapacity is required in the late production period,a larger production casing, that is, the productioncasing ofF177.8 mm (7 in.) for conventional wellsand the production casing ofF244.5 mm (9 5/8 in.)for sand control wells, can be adopted in order toleave some selection margin for adopting the elec-tric submersible pump with larger dischargecapacity in the future. For instance, a higher dailyliquid production rate can be obtained by selectingthe G-160 or G-225 type of pump in Table 3-18.

Selection and Determination ofTubing and Production Casing Sizesfor Gas Lift Oil Production Well

Gas lift production is especially adaptable tosand production wells, medium and low viscos-ity oil wells, high gas-oil ratio wells, deep wells,and directional wells, and is an important artifi-cial lift production mode. The advantages and


limitations of gas lift production are listed inTable 3-19.

The modes of gas lift include continuous gas-lift and intermittent gas-lift. The intermittentgas-lift can be further divided into conventionalintermittent gas-lift, chamber gas-lift, andplunger gas-lift. The continuous gas-lift is onlydiscussed because the daily liquid productionrate of intermittent gas-lift is much lower thanthat of continuous gas-lift.

The selection procedures of tubing and pro-duction casing sizes for a gas lift well are asfollows:

1. Predict the daily liquid production ratelevel QL.

2. Determine the tubing and production casingsizes meeting the requirement of daily liquid

production rate QL for a single-string gas-liftwell using Tables 3-20 and 3-21.

The tubing and production casing sizes of thegas lift well with a high production rate underthe condition of tubing-casing annulus produc-tion (known as reverse lift, that is, gas injectioninto tubing and oil production from annulus)are selected and determined using the followingrecommended procedure:

1. On the basis of the possibly provided gasinjection rate, gas injection pressure, and gasproperties, the tubing with sufficiently smallfrictional pressure drop is selected.

2. A sensitivity analysis of production casingsize is made and the optimum production cas-ing size is selected and determined.

TABLE 3-17 Matching Partial Chinese Electric Submersible Pumps with Tubingand Production Casing

ManufacturerModelNumber

TubingSize (mm)

RatedDischargeCapacity (t/d)

OutsideDiameter (mm)

Casing SizeRecommended (in.)

ConventionalWell

GravelPack Well

Tianjing ElectricMotor

A10A15A20A42A53

60.3, 73.060.3, 73.060.3, 73.060.3, 73.060.3, 73.0

100150200425500

9595959595

5½5½5½5½5½

77777

Zibo SubmergedElectric PumpManufacturer

5.5QD1005.5QD1605.5QD2005.5QD2505.5QD3205.5QD425

60.3, 73.060.3, 73.060.3, 73.060.3, 73.060.3, 73.060.3, 73.0

100160200250320425

100, 98100, 98100, 98100, 98100, 98100, 98

5½5½5½5½5½5½

777777

Huxi ElectricMotorManufacturer

QYB120-75QYB120-100QYB120-150QYB120-200QYB120-250QYB120-320QYB120-425QYB120-550

60.3, 73.060.3, 73.060.3, 73.060.3, 73.060.3, 73.060.3, 73.060.3, 73.060.3, 73.0

75100150200250320425550

100, 98100, 98100, 98100, 98100, 98100, 98100, 98100, 98

5½5½5½5½5½5½5½5½

77777777

Note: The electric submersible pump in this table should be used in the production casing of 5 1/2 in. The tubing sizes include 60.3 mm(2 3/8 in.) and 73.0 mm (2 7/8 in.).


TABLE 3-18 Matching TRW Reda Pumps Electric Submersible Pump with Tubing andProduction Casing

ModelNumber

OutsideDiameter(mm)

Type ofPump

MaximumPower (kw)

TheoreticalDischargeCapacity (t/d)

Casing SizeRecommended (in.)

ConventionalWell

GravelPack Well

338 85.9 A—10A—14EA—25EA—30EA—45E

6262626279

33�6658�8690�140115�195160�240

127 mm (5) 177.8 mm (7)

400 101.6 D—9D—12D—13D—20ED—26D—40D—51D—55ED—82

6262626278787878161

26�5333�6653�8075�115106�146125�240180�260190�320280�480

139.7 mm (51/2) 177.8 mm (7)

450 117.35 E—35EE—41EE—100

9999161

135�200140�235380�560

139.7 mm (51/2) 177.8 mm (7)

540 130.3 G—52EG—62EG—90EG—110G—160G—180G—225

161161161224224224224

210�310240�360320�480420�600580�840660�960636�1140

177.8 mm (7) 244.5 mm (95/8)

TABLE 3-19 Advantages and Limitations of Gas Lift Production

Method Advantages Limitations

Gas lift Low deep well investment cost and lift cost.Most effective for high gas-liquid ratio well.Low lift operation cost for sand production

well.Easy to change production conditions, wide

adaptive range.Adaptable to slant well and crooked well.Appropriate to high liquid production

rate well.Convenient for production test.

Sufficient gas source adjacent to the oil field is required.High cost required by purchasing the gas lift gas.High lift cost when corrosive gas exists.Difficult to maintain low downhole liquid level when

perforation interval is long.Unsafe high-pressure gas.Production casing is required to be able to bear pressure.


Case 15. On the basis of the given data in Case5, the production technology of tubing-casingannulus gas lift is adopted. Try analyzing theoptimum tubing and production casing sizes forthe production rate of 3200 m3/d under the gaslift production mode when the reservoir pressureis reduced to 13 MPa. In order to be convenientfor transporting, the wellhead tubing pressure of0.6 MPa is necessary. The maximum gas injec-tion flow rate of 10 � 104 m3/d can be providedand the gas injection pressure is 15 MPa.Solving Process. Under the condition of tubing-casing annulus gas lift, the gas flow in tubingshould be studied in order to determine thetubing size. If the tubing size is too small,the frictional resistance may be high due to thereverse direction of frictional resistance againstthe gas flow. However a tubing that is too largemay increase the cost. The tubing sensitivity anal-ysis is conducted and the gas injection point pres-sure vs. the inside diameter of the tubing curve isobtained (Figure 3-29). The 3 ½-in., 4-in., and

4 ½-in. ID tubings have close gas injection pointpressures (that is, close frictional resistances). Inconsideration of decreasing the cost and becausethe gas injection rate of 10 � 104 m3/d is not nec-essarily required, the 3 1/2-in. ID tubing isselected. The 3-in. ID tubing has a relatively largeeffect on gas injection point pressure; thus it isinappropriate.

TABLE 3-20 Matching of Tubing with Production Casing for Single-String Gas-Lift Well

MinimumLiquid ProductionRate (t/d)

MaximumLiquid ProductionRate (t/d)

Tubing ID mm(OD in.)

Casing Size Recommended (in.)

ConventionalWell

GravelPack Well

4�8 55 26.6(1.315) 5�51/2 7

8�12 96 35.1(1.660) 5�51/2 712�20 159 40.3(1.990) 5�51/2 731�40 397 50.3(23/8) 51/2 750�80 476 62.0(27/8) 51/2 730�120 636 75.9(31/2) 51/2 7159�240 1590 100.5(41/2) 51/2�7 7

TABLE 3-21 Matching Tubing with Production Casing for Tubing-Casing Annulus Gas-LiftWell (Medium Production Rate)

Minimum LiquidProduction Rate (t/d)

Maximum LiquidProduction Rate (t/d)

TubingSize (in.)

ProductionCasing Size (in.)

476 1270 23/8 51/2795 2380 23/8 7.0636 1900 27/8 7.0500 1590 31/2 7.0

FIGURE 3-29 Frictional pressure drop analysis of tubing.


The casing size sensitivity analysis is conducted.Figure 3-30 shows that under the gas injection ratelower than 10 � 104m3/d, the 12.71-in., 6.97-in.,and 6.36-in. ID casings cannot meet the produc-tion requirement due to the too large annulus ofthe former (high slippage loss) and the too smallannulus of the latter two (high friction loss). Theproduction casing size vs. gas injection rate curveis obtained by using the four casing sizes meetingthe requirement and the corresponding gas injec-tion rate under the liquid production rate of3200 m3/d (Figure 3-31). In order to achieve therequired production rate of 3200 m3/d, the pro-duction casing size of 9 5/8 in. (222.4 mm ID) hasthe minimum necessary gas injection rate and thehighest efficiency; thus, it is the optimum produc-tion casing size.

Selection and Determination ofTubing and Production Casing Sizesfor a Screw Pump Production Well

This type of pump is appropriate to the produc-tion well with crude oil viscosity lower than2000 MPa � s, sand content lower than 5%, dis-charge head of 1400–1600 m, discharge capacitylower than 200 m3/d, and working temperaturelower than 120�C. With the increase of high-viscosity crude oil production and high-viscositypolymer gas production by tertiary recovery inrecent years, oil production using a screw pumphas been widely used. In the late 20th century,with the advance in synthetic rubber technologyand vulcanizing binding technology, the screwpump has been greatly improved in France. Atpresent, the screw pump has been adapted to theproduction of oil with viscosity lower than15,000 MPa � s, sand content lower than 60%,and temperature not exceeding 120�C, and it hasa discharge head up to 3000 m and dischargecapacity up to 1050 m3/d. A screw pump has alarge discharge capacity and a slightly large out-side diameter. The tubing and production casingsizes for a screw pump well can be determinedby reference to Table 3-22 on the basis of the lateliquid production rate (water cut of 95%) pre-dicted by the development program.

Selection and Determination ofProduction Casing Size for Dual-String Production Well

Selection and Determination of ProductionCasing for Dual-String Gas Lift Well. Theselection procedure of production casing sizefor a dual-string gas lift production well is asfollows.

1. The daily liquid production rates QL1 andQL2 of upper and lower oil reservoirs arerespectively predicted.

2. The tubing sizes corresponding to QL1 andQL2 are obtained using Table 3-20.

3. The recommended production casing size isobtained using Table 3-23 on the basis ofthe tubing sizes obtained.

FIGURE 3-30 Effect of casing size on gas lift performancecurve (the curves are obtained by calculating under varioustubing IDs).

FIGURE 3-31 The casing size required by necessaryproduction rate vs. gas injection rate.


Case 16. A certain oil well includes two oil reser-voirs, that is, upper and lower oil reservoirs, anddual-string separate-zone production in a wellunder gas lift is designed. The daily liquid pro-duction rate QL1 of 450 m3/d for the upper reser-voir and the daily liquid production rate QL2 of1000 m3/d for the lower reservoir are predicted.Try selecting the production casing size.Solving Process. Using Table 3-24, the tubingof F73 mm (2 7/8 in.) with a collar of 89.5 mm

OD is appropriate for the upper reservoir,while the F101.6 mm (4-in.) tubing with a collarof 121 mm OD is appropriate for the lowerreservoir. The sum of the two collar ODs hasreached 210.5 mm (8 1/4 in.). In considerationof the clearances between the tubings andbetween tubing and casing, in which the packershould be set, at least a F244.5 mm (9 5/8-in.)production casing should be selected (seeTable 3-24).

TABLE 3-22 Relation between Theoretical Discharge Capacity and MaximumOutside Diameter of Screw Pump

ProducingArea

ConnectingTubing[mm (in.)]

TheoreticalDischargeCapacity (mm)

MaximumOutside Diameterof Pump (mm)

Adaptable MinimumCasing Diameter[mm (in.)]

China 60.3(23/8) 4�17 73 127(5)73.0(27/8) 32�180 90 139.7(51/2)88.0(31/2) 35�108 114 139.7�177.8(51/2�7)101.6(4) 64�500 114 139.7�177.8(51/2�7)

Other countries 60.3(23/8) 15�80 78 127(5)73.0(27/8) 60�240 94 139.7�(51/2)88.0(31/2) 120�300 108 139.7�177.8(51/2�7)101.6(4) 180�840 120 139.8(7)

127.0(5) 430�1000 138 139.8(7)

TABLE 3-23 Matching of Tubing Size* with Production Casing Size* for Dual-StringGas-Lift Well

Upper-Reservoir(or Lower-Reservoir)Gas-Lift Tubing (1) Size (in.)

Upper-Reservoir(or Lower-Reservoir)Gas-Lift Tubing (2) Size (in.)

Minimum Casing SizeRecommended (in.)

1.315 1.315�27/8 51/21.660 1.315�27/8 51/21.990 1.315�27/8 51/2�723/8 1.315�27/8 51/2�727/8 1.315�27/8 51/2�731/2 1.315�27/8 7�95/841/2 1.315�27/8 7�95/8

1.315�27/8 95/8�113/431/2 31/2 95/841/2 31/2 103/4

Note: If a large value is taken as the tubing (2) size, the casing size enlarged by one grade is taken.*Tubing and casing sizes mean outside diameter.


Selection and Determination of ProductionCasing Size for Other Dual-String ProductionWell. For the oil well with great interzone dif-ference, dual-string production can adjust theinterzone contradiction. The production casingsize for a dual-string production well is muchlarger than that of a single-string productionwell. The tubing size required by each zone isselected using the previously mentioned method,while the production casing size correspondingto a dual-string production well can be selectedin accordance with Table 3-24.Selection and Determination of ProductionCasing Size for Oil Production Well ofElectric Submersible Pump with Y-ShapedAdapter. An electric submersible pump with aY-shaped adapter can be used for oil wells (espe-cially offshore oil wells) in which multizone pro-duction, production logging, through-tubingperforation, and coiled tubing operation will beconducted.

The production casing size under this condi-tion can be selected in accordance with thethinking and method of selecting and determin-ing production casing size for a dual-string pro-duction well (Table 3-24). At present, it iscommon that a tubing of 2 7/8 in. and a bypathof 2 3/8-2 7/8 in. are run in the production casingof F244.5 mm (9 5/8 in.).

3.6 EFFECTS OF STIMULATIONON TUBING AND PRODUCTIONCASING SIZE SELECTION

Stimulation mainly includes hydraulic fracturingand acidizing and is used for both the measureof putting into production and the measure ofblocking removal and increasing production rate.No special requirement for tubing size should bemet during matrix acidizing due to the lower dis-placement. However, the hydraulic sand fractur-ing of the sandstone reservoir and the hydraulicsand fracturing and acid fracturing of the car-bonatite reservoir (especially for deep wells andhigh breakdown pressure wells) may affect theselection of tubing and production casing sizes.

Hydraulic fracturing and acidizing are high-pressure high-displacement operations. The higherhydraulic friction resistance can be caused by ahigh pumping rate in the wellbore, thus leadingto the excessive wellhead pressure and the unavail-able power loss of the fracturing unit. Thus thereservoir cannot be fractured. The relationshipamong wellbore friction loss, wellhead pressure,and reservoir breakdown pressure is shown inEquation (3-20).

(3-20)

pwh ¼ aHþ Dpf � 10�6rgHþ Dph

TABLE 3-24 Recommended Production Casing Size for Dual-String Production Well

Tubing Size Required by Upper(or Lower) Reservoir (in.)

Tubing Size Required by Lower(or Upper) Reservoir (in.)

Minimum Casing SizeRecommended (in.)

1.315 1.315�31/2 51/21.315 1.315�31/2 51/21.990 1.315�27/8 51/223/8 1.315�27/8 51/2�71

23/8 31/2�4 727/8 19/32�27/8 51/2�71

27/8 23/8�27/8 731/2 2�27/8 731/2 31/2 95/841/2 39/32�2 741/2 23/8�31/2 95/841/2 41/2 103/4

1Tubing and casing sizes mean outside diameters.


where pwh ¼ wellhead pressure during fractur-ing, MPa; a ¼ reservoir breakdown pressuregradient, MPa/m; H ¼ depth in middle of reser-voir, m; Dpf ¼ fraction loss of fracturing fluidin wellbore, MPa; r ¼ fracturing fluid density,kg/m3; g ¼ gravitational acceleration, m/s2;Dph ¼ total friction resistance of fracturing fluidthrough perforations, MPa.

It is shown that when the reservoir breakdownpressure aH is high (breakdown pressure gradienta is great or well is deep), pwh can only bereduced by decreasing Dpf and Dph. In general,Dpf is much greater than Dph. Thus the key liesin decreasing the wellbore friction loss Dpf.

The fracturing fluids used in the field includeNewtonian and non-Newtonian fluids. The frac-turing fluid of Newtonian fluid has the wellborefriction resistance pressure drop described inEquation (3-21):

(3-21)

Dpf ¼ fHv2

2Dg�10�2

where f ¼ friction resistance coefficient, dimen-sionless; H ¼ well depth, m; D ¼ inside diameterof tubing, m; v ¼ fracturing fluid flow velocity inwellbore, m/s; Dpf ¼ friction resistance pressuredrop, MPa; g ¼ gravitational acceleration, m/s2.

The relationship between the displacement Qand the flow velocity v during fracturing isshown in Equation (3-22).

(3-22)

v ¼ Q

15pD2

where Q ¼ fracturing fluid pumping rate, m3/min;D ¼ inside diameter of tubing, m; V ¼ fracturingfluid flow velocity, m/s.

By substituting Equation (3-22) into Equation(3-21), the formula in Equation (3-23) isobtained:

(3-23)

Dpf ¼ 2:29� 10�7fHQ2

D5

where Dpf ¼ friction resistance pressure drop,MPa; Q ¼ fracturing fluid, m3/min; D ¼ insidediameter of tubing, m.

The other symbols are as explained earlier.It is shown that the Dpf is directly proportional

to the well depth H and the square of the pump-ing rate and is inversely proportional to the fifthpower of the tubing ID. The pumping rate ofhydraulic fracturing is generally 2–6.0 m3/minand will be up to about 6 m3/min during thelimited entry fracturing.

For low-permeability tight sand, the scale ofhydraulic fracturing has been greatly increasedand the massive hydraulic fracturing (MHF) tech-nique has been developed. The hydraulic fluidvolume is up to several thousand cubic meters,the proppant volume is up to several hundred toseveral thousand tons, and the fracture length isup to several hundred to several thousand meters.In the medium and late stage of the MHF opera-tion, the fracture length has been great and thefluid loss into formation through the fracture wallface may be great. In order to continue to extendand spread the fracture, a high pumping rate isrequired. This can be explained using the formulain Equation (3-24):

(3-24)Q� Dt ¼ Vw þ DVF

where Q ¼ fracturing fluid pumping rate, m3/min;Dt ¼ unit time, min; Vw ¼ fluid loss into for-mation through fracture wall face per unit time,m3; DVF ¼ fracture volume increment per unittime, m3.

It is shown that in order to maintain the frac-ture volume increment DVF per unit time as apositive value (that is, to increase continuouslythe fracture volume), a high pumping rate offracturing fluid is necessary because the fluidloss into formation through the fracture wallface per unit time increases with the increase infracture length. The fracture extension andspreading cannot be achieved by a fracturingfluid volume lower than the fluid loss. The mas-sive hydraulic fracturing is a fracturing opera-tion with a very high pumping rate, which iseven higher than that of limited entry fracturingand up to 6–10 m3/min.

The deep well and high pumping rate operationhas a large wellbore friction resistance pressure


drop Dpf . The methods of reducing friction resis-tance pressure drop include the method of reduc-ing effective viscosity of fracturing fluid oradding a friction-reducing agent into fracturingfluid (which can only reduce friction resistance to40% to 60% of clear water friction resistance)and the method of increasing tubing size, whichis the most effective. This can be shown inTable 3-25 on the basis of Equation (3-23).

Table 3-25 indicates that the reservoir cannotbe fractured by using the tubing of 50.7 mm ID(2 3/8 in.) and 1000-type fracturing unit underthe pumping rate of 3 m3/min. However, the res-ervoir has begun to be fractured by using a tub-ing of slightly larger ID to 62.0 mm ID (2 7/8 in.)and the wellhead pressure of 78.44 MPa. Thereservoir can be easily fractured when the tubingID increases and is above 75.9 mm (3 ½ in.).Under the pumping rate of 6 m3/min, the reser-voir cannot be fractured by using a tubing ofsmaller ID than 75.9 mm (3 ½ in.). However,the reservoir can be easily fractured when thetubing ID is above 88.6 mm (4 in.).

Figures 3-32 and 3-33 show the pumpingrate vs. friction loss relationships obtained byHalliburton under various tubing and casing IDs.

When a non-Newtonian fluid is used as frac-turing fluid or acidizing fluid, the relationbetween shear stress and shear rate can be con-sidered as a power law model:

t ¼ K0gn

0

where t ¼ shear stress; g ¼ shear rate; K0 ¼ liquidconsistency coefficient; n0 ¼ liquid flow regimeindex.

K0 and n0 are determined by experiment. Thefriction loss can still be calculated using theone-way resistance pressure drop and Equation(3-21). The friction resistance coefficient is alsoobtained by experiment and is related to the Rey-nolds number and n0 values. It should be indicatedthat the water-base gel fracturing fluid used pres-ently is basically a viscoelastic fluid, so the actualsituation cannot be accurately reflected by calcula-tion in accordance with the power-lawmodel. Thefriction resistance pressure drop value is obtainedby using the instant pumping off in the fracturingoperation. The value obtained is compared withthe clear water friction resistance pressure dropvalue and the percentage is obtained. The water-base plant gel fracturing fluid friction loss in tub-ing is generally lower than the friction loss of clearwater and is related to fracturing fluid, material,formulation, and shear rate. The water-base plantgel fracturing fluid friction loss is generally about60% of clear water fracturing fluid friction loss.The friction resistance pressure drop of hydroxy-propylguar (HPG) gum titanium gel fracturingfluid has been lower than 45% of that of clearwater under some conditions. Because the long-chain linear molecules may restrain the turbulenceof water and reduce the friction resistance, the highmolecular polymer can reduce the friction resis-tance pressure drop. However, it should still be

TABLE 3-25 Calculated Values of Friction Resistance Pressure Drop in Tubing DuringFracturing and Wellhead Pressure

Tubing Size[ID mm (OD in.)]

Tubing Friction Loss (MPa) Wellhead Pressure (MPa)

Pumping Rate3 m3/min




50.3(23/8) 107.99 430.81 152.95 475.77

62.0(27/8) 33.48 133.37 78.44 178.3375.9(31/2) 12.89 51.26 57.85 96.2288.6(4) 5.76 22.87 50.72 67.83100.3(41/2) 2.87 11.38 47.84 56.34114.1(5) 1.56 6.16 46.52 51.11

Note: Clear water viscosity is 1 MPa � s. Well depth H ¼ 4000 m. Breakdown pressure pf¼ 92MPa. Relative density of fracturing fluid is 1.2.


indicated that the friction loss sensitivity is greatlyaffected by the tubing size. For instance, duringhydraulic fracturing in a certain area a small tub-ing of 2 7/8 in. was first used, the friction resistancepressure drop exceeded 30 MPa under the pump-ing rate of 2 m3/min and the tubing length of

3000 m, the operating wellhead pressure exceeded70 MPa, and the reservoir could not be fracturedunder a high breakdown pressure. When thetubing size was changed to 3 ½ in., the operatingwellhead pressure was reduced to about 50 MPaand the reservoir could be fractured. Under the

FIGURE 3-32 Friction loss vs. pumping rate for clear water fracturing fluid.


aforementioned conditions, the clearwater frictionresistance pressure drop is 46.5 MPa (Figure 3-32)and the friction resistance pressure drop of frac-turing fluid is 63.5%of that of clear water. Despitethe fact that the friction-reducing effect of polymer

has been achieved, the friction resistance pressuredrop value is still high. When the tubing size isincreased from 2 7/8 in. to 3 ½ in., the friction resis-tance pressure drop of clear water is changed intoonly 17.6 MPa, that is, 40% of that of 2 7/8-in.

FIGURE 3-33 Friction loss vs. pumping rate for fracturing fluid.


tubing. When the friction-reducing effect offracturing fluid is also considered, the pumpingrate is possibly increased (for example, to3 m3/min), the friction resistance pressure drop isonly 35 MPa, and the wellhead pressure can bedecreased to a value below 54MPa, thus improv-ing the fracturing operation condition.

With the increase in tubing size, the frictionresistance pressure drop in tubing decreases rap-idly. Therefore, for a high breakdown pressurewell or deep well, a relatively large tubing sizeand corresponding large production casing sizeshould be designed.

The tubing friction resistance pressure dropand the operating wellhead pressure are pre-dicted under the different tubing sizes on thebasis of reservoir breakdown pressure gradientand well depth in accordance with Equation(3-20) and Equation (3-21) or Figures 3-32and 3-33. The minimum tubing size can beselected by the criterion of operating wellheadpressure �80% � working pressure of thefracturing unit. The corresponding minimum

production casing size is selected in accor-dance with the matching relation between tub-ing and production casing sizes, as shown inTable 3-4. On this basis, by reference to thepreselected tubing and production casing sizesfor the artificial lift well, appropriate tubingand production casing sizes are selected anddetermined.

3.7 SELECTION ANDDETERMINATION OF TUBING ANDPRODUCTION CASING SIZES FORHEAVY OIL AND HIGH POUR-POINTOIL PRODUCTION WELLS

Heavy oil is asphalt-based crude oil and haslow or no flowability due to the high contentof colloid and asphaltene and the high viscosity.The heavy oil viscosity is sensitive to change intemperature (Figure 3-34). With the increase intemperature the heavy oil viscosity may rapidlydecrease and vice versa. This inherent featureof heavy oil makes the recovery methods

FIGURE 3-34 Heavy oil viscosity vs. temperature.


different from that of conventional light oil andmakes the recovery process complicated. Atpresent in China the ordinary heavy oil with aviscosity lower than 150 MPa � s under reservoirconditions is recovered by waterflooding, whilethe ordinary and extra-heavy oils with a viscos-ity higher than 150 MPa � s are recovered bysteam injection.

Heavy Oil Recovery byWaterflooding

The heavy oil with a viscosity lower than150 MPa � s under reservoir conditions is com-monly recovered by waterflooding because thisheavy oil generally contains a higher dissolved-gas content and has a certain flowability underreservoir conditions, despite the fact that thesurface crude oil viscosity may be up to severalthousand millipoises. The features of waterflood-ing include mature technique, simple technology,relatively low investment, and good economicbenefit. Therefore, waterflooding is the firstselected recovery method. For instance, the con-ventional waterflooding has been adopted in theGudao, Gudong, Chengdong, and Shengtuo oilfields of the Shengli oil region and the Jing 99block, Niuxintuo, and Haiwaihe oil fields ofthe Liaohe oil region, and good developmentresults have been achieved through continuousadjustment.Flowing Production. The flowability of heavyoil is low due to the high intermolecular frictionresistances of colloid and asphaltene. The fric-tion head loss of fluid flow in tubing can becalculated using the hydraulics formula inEquation (3-25):

(3-25)

Hf ¼ fL

D� v

2

2g

whereHf ¼ friction head loss, m; f ¼ friction resis-tance coefficient, dimensionless; L ¼ tubing settingdepth, m; D ¼ tubing diameter, m; v ¼ liquidflow velocity, m/s.

The friction head loss vs. tubing setting depthrelationships under a certain heavy oil viscosity

and the different tubing diameters are calcu-lated using Equation (3-25) and are shown inFigure 3-35.

It is well known that the higher the crude oilviscosity, the greater the friction head loss. Asshown in Figure 3-35(a), under the same crudeoil viscosity, the friction head loss increaseswith the increase of fluid flow velocity in

FIGURE 3-35 Effect of tubing diameter on frictionhead loss.


tubing and decreases with the increase of tub-ing diameter. For heavy oil with high viscosity,tubing with a relatively large diameter shouldbe adopted in order to maintain flowing pro-duction, and the corresponding production cas-ing with a larger diameter should also beselected.Oil Production by Pumping Unit and DeepWell Pump. Because of the limitations of tradi-tional ideas, small size tubing was set in mostheavy oil wells in the early development period.On the downstroke of the sucker rod, thedropping velocity of the sucker rod is reducedby the great friction resistance of heavy oil tothe sucker rod, and the movement of the suckerrod lags behind the movement of the hangingpoint of the horsehead. When the hanging pointis rising, the sucker rod is still dropping. Notonly the normal movement of sucker rod maybe affected, but also the impact of the horseheadon the sucker rod may be caused. Thus theimpact load may be generated, the service lifeis reduced, and even mechanical failure mayresult (see Figure 3-36).

In view of this, when the pumping unit anddeep well pump are used for producing heavyoil, the upstroke friction resistance and thedownstroke resistance should first be reduced.The friction resistance of the wellbore liquid col-umn to the sucker rod can be calculated usingthe formula shown in Equation (3-26):

(3-26)

Fr ¼ 2pmLv

1031

ln mþ 4b2

aþ 4b

a

!

v ¼ Sn30

m ¼ dtdr

a ¼ m4 � 1� ðm2 � 1Þ2In m

b ¼ m2 � 1

2In m� 1

where Fr ¼ friction resistance of wellbore liquidcolumn to sucker rod, N; m ¼ liquid viscosity,MPa � s; L ¼ pump setting depth, m; v ¼ suckerrod movement velocity, m/s; S ¼ length of stroke,m; n ¼ strokes per minute, min�1; dt ¼ tubingdiameter, m; dr ¼ sucker rod diameter, m.

It is shown that the friction resistance isrelated to the wellbore liquid viscosity, flowvelocity, and tubing diameter. The friction resis-tance curves under the different tubing diame-ters and the different crude oil viscosities(Figure 3-37) indicate that the friction resistanceincreases with the increase in viscosity and thedecrease in tubing diameter. Therefore, thelarge-diameter tubing of 101.6–114.3 (3 ½-4 ½in.) should be used in order to reduce the frictionresistance and reduce the sucker rod flotationand impact on the horsehead.

When heavy oil is produced by large-diametertubing and pumps, the friction resistance andsucker rod flotation can be reduced, and thepump stroke efficiency and pumping rate canbe increased. Under the conventional water-flooding of heavy oil, the oil-water viscosityratio is high, the early water breakthroughoccurs, the water cut rapidly increases, most oilshould be produced in the high water cut period,the water-free recovery factor is only 2% to 5%,and the yearly average water cut increases byabout 3%. When the water cut is higher than50%, the liquid production rate should beincreased by 2 to 20 times in order to maintaina stable oil production rate (see Table 3-26).

FIGURE 3-36 Crude oil viscosity effect during heavy oilpumping (sucker rod flotation).


Therefore, in order to increase the liquid produc-tion rate and maintain a stable oil productionrate, the tubing diameter should also beincreased.

In the Gudao oil field of the Shengli oil region,the surface stock tank oil viscosity is 250–5700MPa � s, the reservoir oil viscosity is 20–130MPa � s, and the oil-water viscosity ratio is 80–350. This oil field was put into production in1973 and started waterflooding in April 1974.The water cut increased rapidly due to the highoil viscosity, and a large amount of crude oilwould be produced in the high water cut period.In order to maintain a stable oil production rateand increase the liquid production rate, the origi-nal pumps of F43–56 mm have been changed intopumps of F70 mm and F83 mm. When pumps ofF43–56 mm were used, the individual-well dailyoil production rate was 20 t/d, and the tubingdiameter of 2 7/8 in. could meet the requirement.When the water cut increases to 80%, the liquidproduction rate of 100 t/d is required by retainingthe stable oil production rate. Thus the oil wellpumps of F70 mm and F83 mm are required,the corresponding tubing diameter should beabove 3 ½ in., and the relatively large productioncasing diameter should be selected in the wellcompletion design.

Heavy Oil Recovery bySteam Injection

Huff and Puff. Huff and puff is a commonlyused method of producing heavy oil. In Chinamost heavy oil is produced using huff and puff.At the steam injection stage, the injected steamheats the reservoir, the crude oil viscosity isdecreased, and the flowability of crude oil isincreased. When a well is put on, the heatedcrude oil flows into the well under the effects

FIGURE 3-37 Effects of tubing diameter on frictionresistance of liquid to sucker rod.

TABLE 3-26 Water Cut vs. Liquid Production Rate

Water cut (%) 0 10 20 30 40 50 60 70 80 90 95

Liquid production rate (t/d) 15.0 16.6 18.8 21.4 25.0 30.0 37.5 50.0 75.0 150 300


of elastic energy and gravity. In the wellbore,with the flow of crude oil toward the wellhead,the fluid temperature gradually decreases dueto heat conduction, and the oil viscosity gradu-ally increases. Therefore, both the oil pumpingcondition during production and the wellboreheat loss condition during steam injectionshould be considered in the huff and puff welltubing string design.

The heat-insulated tubing string should be setin the well in order to decrease wellbore heatloss and improve steam quality at the steaminjection stage. This string consists of tubing,insulating layer, and outside pipe. The differentstring sizes have different overall heat transfercoefficients, and the insulating layer thicknessand annulus size will play important roles.The overall heat transfer coefficients for differ-ent sizes of wellbore string configuration(Table 3-27) indicate that the small heat-insulated string has great overall heat transfercoefficient and great wellbore heat loss. In theproduction casing of 7 in., the insulating effec-tiveness of the heat-insulated string of 2 3/8 in.� 4 in. is higher than that of the heat-insulatedstring of 2 7/8 in. � 4 in. due to the larger insulat-ing layer thickness. However, the mechanicalstrength (in a deep well) and safety load of theformer are lower than that of the latter. More-over, the low bottomhole steam pressure andhigh wellbore steam pressure are caused by theformer due to the high flow velocity, high fric-tion resistance, and great wellbore pressure dropof the small tubing size (Figure 3-38). Therefore,

on the premise of ensuring good insulating effec-tiveness, a larger diameter string should be usedto the full extent for steam injection and laterpumping.

The liquid production rate of huff and puff ishigh. The condensate water of injected steamshould be rapidly produced, and the crude oilshould be produced as much as possible, thusthe huff and puff production effectiveness may

TABLE 3-27 Overall Heat Transfer Coefficient U1[W/(M2 � K)] under Different Sizesof Wellbore String Configuration

No.Sizes of WellboreString Configuration (in.)

Insulating LayerThickness (mm)

AnnulusClearance (mm)

Steam InjectionTemperature (ºC)

250 300 350

1 7�23/8�4 17 28.7 1.91 2.52 2.67

2 7�27/8�4 10.5 28.7 4.13 4.48 4.783 7�27/8�41/2 16 22.5 3.58 3.79 4.024 51/2�23/8�31/2 10.4 17.7 4.18 4.85 5.415 51/2�23/8�4 16.8 11.1 3.99 4.01 4.33

FIGURE 3-38 Wellhead steam pressure under differenttubing sizes.


be increased. As a result, the tubing size shouldmeet the requirement of the liquid production rate.If a small size tubing is used, the fluid flow velocitymay be very high under a high production rate.Under the same tubing size, with the increase inflow rate or (stroke � strokes per minute) value,the friction resistance of liquid to sucker rod willincrease (Figure 3-39), and the friction resistancewill increase with the increase in oil viscosity(Figure 3-40). Thus the problems (including suckerrod flotation, impact of the horsehead on thesucker rod, and decrease in stroke efficiency) thatmay be generated under the conventional water-flooding of heavy oil will occur.

In order to reduce friction resistance duringthe movement of the sucker rod in the tubingliquid, a larger diameter tubing should beselected. For instance, when the liquid viscosityis 1000 MPa � s, and the working parameterS � n is 3.3 m � 6 min�1, the friction resistanceof 2 7/8-in. tubing is 1.4 times that of 3 ½-in.tubing and 2.2 times that of 4 ½-in. tubing(Table 3-28). Obviously, the friction resistancecan be effectively reduced by using the tubingof 3 ½ to 4 ½ in. Correspondingly, a larger pro-duction casing should be adopted.

It is shown that a large diameter string isrequired by the huff and puff during both the

FIGURE 3-39 Flow velocity vs. friction resistance to sucker rodunder different tubing sizes.

FIGURE 3-40 Oil viscosity vs. friction resistance to sucker rodunder different tubing sizes.


steam injection and the liquid production inorder to increase the production effectiveness ofthe huff and puff.Heavy Oil Recovery by Steam-Flooding.Steam-flooding is an important method of heavyoil recovery. When heavy oil is produced by huffand puff to some extent, with the decrease in reser-voir pressure and the increase in water saturation,the effectiveness will decrease gradually. In orderto further enhance the crude oil recovery factor,the huff and puff should be substituted by steam-flooding. Laboratory studies and field practiceindicate that the liquid productivity of the produc-tion well will greatly affect the recovery effective-ness of steam-flooding, and the liquid productionrate should be higher than the steam injection rate;that is, the production-injection ratio should be upto 1.2–2.0 in order to achieve good recovery effec-tiveness. For instance, in the steam-flooding pilottest area of the Du 66 block of the Shuguang oilfield in the Liaohe oil region, the optimized steam

injection rate is 135 t/d. Under this steam injectionrate, the steam-flooding production effectivenessof the different liquid production rates of the pro-duction well indicate that when the liquid produc-tion rate of the production well is lower than orequal to the steam injection rate, that is, the pro-duction-injection ratio is lower than or equal to1, the production effectiveness of steam-floodingis low (the oil-steam ratio and recovery factor arelow); when the liquid production rate of the pro-duction well is higher than the steam injectionrate, that is, the production-injection ratio ishigher than 1, the production effectiveness ofsteam-flooding is improved (Table 3-29).

The Tangleflags oil field in Canada has stocktank oil viscosity of 13,000 MPa � s, reservoirthickness of 27 m, and reservoir depth of450 m. The combined steam-flooding tests ofvertical and horizontal wells were conducted bySceptre in 1988 and met with success. The mainexperience and practice include:

TABLE 3-29 Effects of Liquid Production Rate of Production Wellon Steam-Flooding Effectiveness

LiquidProductionRate (t/d)

ProductionTime (d)

CumulativeSteamInjection (t)

CumulativeOilProduction (t)

AverageOilProductionRate (t/d)

Oil-SteamRatio

RecoveryFactor (%)

Production-InjectionRatio

Net OilProductionIncrement (t)

80 126 17,010 2410 19.1 0.142 4.1 0.59 992

100 147 19,845 2860 19.5 0.144 4.8 0.74 1206120 218 29,430 3870 17.8 0.132 6.5 0.89 1417140 304 41,040 5190 17.1 0.126 8.7 1.04 1770160 1341 1,81,035 23,050 17.2 0.127 38.8 1.18 7963180 788 1,06,380 16,390 20.8 0.154 27.6 1.33 7525200 751 1,01,385 16,010 21.3 0.158 26.8 1.48 7561

220 706 95,310 15,150 21.5 0.159 25.5 1.63 7207

TABLE 3-28 Friction Resistances to Sucker Rod under Different Tubing Sizesand Different S r n Values

Tubing Diameter (in) 27/8 31/2 41/2 51/2

Friction resistance under different S�n value (N) 2.7�6 � min�1 20,500 14,500 9500 66003.3�6 � min�1 25,000 17,800 11,600 81004.0�6 � min�1 30,400 21,600 14,000 98005.0�6 � min�1 38,000 27,000 17,600 12,300

Note: The results are obtained by calculating under viscosity of 1000 MPa � s and sucker rod diameter of 25 mm.


1. The productivity of the oil reservoir shouldbe fully understood. The drainage radius pre-dicted initially by numerical simulation in thisregion is 50 m. The practical production dataindicate that the drainage radius should be upto 80 m. The predicted maximum liquid pro-duction rate is 650 m3/d, while the actual liquidproduction rate has been up to 1200 m3/d.Due to the initial underestimation of the liquidproduction rate, a pump of 3 3/4 in., which wasinitially set, has been inappropriate for produc-tion and was changed later from 4 3/4 in.through 5 3/4 in. to 7 3/4 in. The correspondingliquid production rate was also increased. Bethat as it may, the high production period wasmissed. Later a pump of 7 3/4 in. was used. Thetubing diameter is 7 5/8 in. and the productioncasing diameter is 10 3/4 in. (Figure 3-41). Dur-ing oil pumping, slow downstroke movementand quick upstroke movement are adopted in

order to increase the fullness coefficient. Theactual liquid production rate is up to 1200 m3/d and the daily oil production rate is 480 m3/dunder thewater cut of 60%. If themaximum liq-uid production rate had initially been predictedaccurately, the effectiveness would be better.

2. The period after steam breakthrough is animportant production period. Before steambreakthrough the production rate of a produc-tion well is relatively low. Only after steambreakthrough can the liquid production ratebe increased and most of the crude oil willbe produced in the period with a water cutof up to 60% to 80%. In this period a suffi-ciently high liquid production rate of the pro-duction well and a production-injection ratiohigher than 2 should be ensured. Thus a suffi-ciently large string and the matching largediameter production casing should be set in aproduction well.

FIGURE 3-41 Typical production well completion in Tangleflags oil field.


High Pour-Point Crude Production

High pour-point crude is a paraffin-based crudeoil and has a high pour point and low viscosity.Crude oil viscosity is highly sensitive to thechange in temperature (Figure 3-42). When thetemperature is higher than the pour point,the crude oil is a Newtonian fluid and the viscos-ity can be reduced to several to several dozenMPa � s. However, when the temperature islower than the wax precipitation point, the fluidconfiguration may change and become non-Newtonian. The crude oil viscosity is not only

related to temperature, but to shear rate. Theflow performance reduces obviously with the de-crease in temperature. Therefore, when thetemperature is higher than the pour point ofoil, the oil viscosity is low, the flowability isgood, and the oil flows easily from reservoir tobottomhole. However, when the crude oil flowsfrom bottomhole to wellhead, with the decreasein temperature, the wax precipitates from thecrude oil. When the temperature is lower thanthe wax precipitation point, the crude oil viscos-ity increases, the flowability decreases, andeven the crude oil cannot flow due to the

FIGURE 3-42 Rheological curves of high pour-pointcrude of Shenbei oil field in Liaohe oil region.

FIGURE 3-43 Concentric string hot-water circulationproduction.


solidification of wax. Thus the key to high pour-point oil production lies in keeping a higher oiltemperature than the pour point. The crude oilflow in the near-wellbore zone and in the well-bore should be ensured and the precipitation ofwax should be prevented.

At present, the following approaches can betaken in order to ensure the normal productionof high pour-point crude:

1. Self-controlled electric heating cable2. Hollow sucker rod (electric heating and

hot-water circulation)3. Hydraulic piston pump4. Electric submersible pump5. Concentric string hot-water circulation (Fig-

ure 3-43)

The former four selections are mainly depen-dent on the liquid production rate and thetechnological conditions, and no special require-ment for production casing size. In the fifthselection, the concentric tubing string configura-tion requires that the outer tubing should belarger than the inner tubing. In general, the outertubing of 4 ½ in. and the inner tubing of 2 7/8 in.are set in the production casing of 7 in., thusforming a hot-water circulation path.

As mentioned earlier, the selection of tubingand production casing sizes may be affected bynatural gas wells, flowing wells, artificial liftwells, stimulation, heavy oil, or high pour-pointoil production. Therefore, these aspects should

be considered when rational tubing and produc-tion casing sizes are determined.

REFERENCES

[1] K.E. Brown, et al., Petroleum Production Technologyof Lifting Methods, vol. 4, Petroleum Industry Press,Beijing, 1990.

[2] J. Mach, E. Proano, K.E. Brown, A Nodal Approachfor Applying Systems Analysis to the Flowing andArtificial Lift Oil or Gas Well. SPE 8025.

[3] H. Duns Jr., N.C.J. Ros, Vertical Flow of Gas andLiquid Mixtures in Wells, 6th World PetroleumCongress, Frankfurt, Germany, 1984.

[4] J. Orkiszewski, Predicting Two-phase Pressure Dropin Vertical Pipe, JPT (6) (1967).

[5] H.D. Beggs, J.P. Brill, A Study of Two Phase Flow inInclined Pipes, JPT (5) (1973).

[6] Wang Deyou, Case History of Nodal Analysis of Oiland Gas Wells, Petroleum Industry Press, Beijing,1991 (in Chinese).

[7] WanRenpu, LuoYingjun, et al., PetroleumProductionTechnology Handbook, vol. 4, Petroleum IndustryPress, Beijing, 1991 (in Chinese).

[8] Drilling Handbook (Party A), Petroleum IndustryPress, Beijing, 1990 (in Chinese).

[9] Wan Renpu, The 7-in. Production Casing SelectionProof, Petroleum Drilling and Production Technology(1) (1981) (in Chinese).

[10] Shilun Li, et al., Natural Gas Engineering, Petro-leum Industry Press, Beijing, 2000 (in Chinese).

[11] Yingchuan Li, et al., Petroleum Production Engi-neering, Petroleum Industry Press, Beijing, 2001(in Chinese).

[12] Wan Renpu, et al., Petroleum Production EngineeringHandbook, Petroleum Industry Press, Beijing, 2000(in Chinese).


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