jpt2008 01 1_eor (1)

Currently available primary- and secondary-oil-production tech-nologies leave behind two-thirds of the oil in place as stranded oil. However, many analysis and field projects have shown that significant oil-recovery increases are possible with improved/enhanced oil recovery (EOR) by gas injection, thermal recov-ery, or chemical injection. The first two methods have proved cost-effective even at low oil prices. Current oil prices have cre-

ated renewed interest in more-costly chemical-based EOR methods such as gel treatment, foam flooding, polymer flooding, alkaline/surfactant/polymer (ASP) flooding, and alkaline flooding. This year, we focus on chemical-based EOR methods. Chemical-EOR methods focus on improving the sweep efficiency by correcting reservoir heterogeneity or controlling fluid mobility, or they focus on increasing displacement efficiency by reducing residual-oil saturation.

Gel treatment usually is intended to improve sweep efficiency and to reduce excess water production in channeled or fracture-dominated mature reservoirs. A newer trend in gel treatment is to apply preformed gels for in-depth treat-ments. These gels have been reported to penetrate deeply into superhigh-per-meability streaks or fractures and seal or partially seal them off, thus creating high flow resistance in formerly watered-out, high-permeability zones. When successful, these gel systems divert a portion of the injection water into areas not previously swept by water.

Foam flooding often is used to reduce gas mobility and to correct reservoir het-erogeneity and increase sweep efficiency for gasflooding. Foam can be injected into the reservoir by coinjection of gas and surfactant solution or by injection of surfactant solution alternating with gas (SAG). Foam stability, surfactant-adsorption reduction, and optimized SAG-process design are the keys to con-trolling the economics of foam flooding.

Polymer flooding is designed to control mobility for waterflooding. High-molecular-weight and new high-temperature salt-resistant polymers have made polymer flooding more economical. Adding either an alkaline or surfactant chemical, or both, in a polymer flood will scour residual oil from the rock, result-ing in higher oil recovery than with polymer flooding alone. However, the scale problem associated with alkaline limits the use of ASP flooding.

Wettability is of major importance to oil recovery, especially for fractured oil-wet carbonate reservoirs where water flows through the fractures but does not imbibe into the matrix because of negative capillary pressure. The chief concern is to develop cost-effective chemical formulations that change the carbonate wettability from oil-wet to water-wet.

Baojun Bai, SPE, is an assistant professor of petroleum engineering at Missouri University of Science and Technology (University of Missouri-Rolla). Previously, he was a reservoir engineer and head of the conformance-control section at the Research Institute of Petroleum Exploration and Development (RIPED), PetroChina. Bai also was a post-doctoral scholar at the California Institute of Technology and a graduate research assistant at the New Mexico Petroleum Recovery Research Center for EOR projects. He holds a BS degree in reservoir engineering from Daqing Petroleum Institute, an MS degree in oil and gas production and development engineering from RIPED, and PhD degrees in petroleum engineering and in petroleum geology from New Mexico Institute of Mining and Technology. Bai serves on the JPT Editorial Committee.

OVERVIEW

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EOR/IORadditional reading available at the SPE eLibrary: www.spe.org

SPE 107095“Field-Scale Wettability Modification—TheLimitations of Diffusive Surfactant Transport” by W.M. Stoll, SPE, Shell International E&P, et al.

SPE 107776“Improved ASP Design Using Organic-Compound/Surfactant/Polymer for La Salina Field, Maracaibo Lake” by E. Guerra, PDVSA Intevep, et al.

SPE 107727“Polymer Flooding: A Sustainable Enhanced Oil Recovery in the Current Scenario” by Ivonete P. Gonzalez da Silva, Petrobras, et al.

SPE 106901“SAGD Optimization With Air Injection” by J.D.M. Belgrave, EnCana Corporation, et al.

42 JPT • JANUARY 2008

JPT

In principle, miscible-gas injection can displace nearly all of the oil from the portions of a reservoir swept by gas. However, reservoir heterogeneity, low gas density, and high gas mobility reduce sweep efficiency and decrease recovery drastically. The use of foam can reduce gas mobility and the effect of heterogeneity, thereby increasing sweep efficiency. An optimal design strategy is proposed for surfactant-alternating-gas (SAG) -foam processes.

IntroductionPrimary- and secondary-recovery meth-ods leave behind up to two-thirds of the oil originally in place in the reservoir. Gas injection can increase the recovery from depleted reservoirs. Injected gas tends to rise to the top of the reservoir because of its low density, then over-ride the oil-rich zone, leading to early gas breakthrough. High mobility of the gas leads to viscous instability, which enhances gravity override and makes heterogeneity much worse by forming high-mobility flow paths.

The use of foam for mobility control, proposed in 1958, traps some bubbles and reduces movement of flowing gas, thereby reducing gas mobility. Trapped gas reduces gas relative per-meability because foam films (lamel-lae) block some of the flow channels. In flowing bubbles, the effective gas viscosity is increased because pore walls and constrictions cause signifi-cant drag. Foam does not change the

water relative permeability function or liquid viscosity.

Foam can be injected into the reser-voir by coinjection of gas and water or by SAG injection (alternating slugs of surfactant solution and gas). For CO2-foam projects, the SAG process also reduces corrosion in surface facilities and pipe. In low-permeability porous media, the SAG process increases gas injectivity. When gas is injected, water is displaced from the near-well region farther into the reservoir, weakening foam near the well. As a result, gas mobility in the near-well region rises, and injectivity increases.

Foam Model Existing models can be divided into local-steady-state models (ranging from simple to more-complex semimecha-nistic models) and dynamic “popula-tion-balance” models. Population-bal-ance models take into account the rate of change of foam texture (i.e., bubble density), which depends on creation, destruction, and trapping of lamellae.

Local-steady-state models use an alge-braic relation (which could be empiri-cal or more physically based) between gas mobility and factors determining

foam texture (e.g., surfactant concen-tration). All these models account for foam having no effect on the relative permeability function for water.

Dynamic population-balance models introduce additional complexity into foam modeling, but in several studies, the results converge to local steady state at distances comparable to pattern or reservoir scale. Therefore, this study used a local-steady-state model.

Methods to describe the flow of foam and the advance of the foam front include the fractional-flow method for 1D flow (with additional restricting assumptions) and reservoir simulation. A commercial simulator was used for this study that is based on the limiting-capillary-pressure concept. This con-cept is detailed in the full-length paper.

Analytical Models Fractional-flow theory has been used to model water/oil or water/gas immis-cible flooding. It also is a useful method for analyzing foam processes, even in conditions under which its assump-tions are not satisfied quantitatively. Assumptions made in these applica-tions are as follows.

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110408, “Success of SAG-Foam Processes in Heterogeneous Reservoirs,” by W.J. Renkema and W.R. Rossen,Delft University of Technology, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November.

Success of SAG-Foam Processes in Heterogeneous Reservoirs

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For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt. The paper has not been peer reviewed.

JPT • JANUARY 2008 43

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Fig. 1—Fractional-flow curves for gas/water flow with and without foam.


• Flow is 1D, through an isothermal permeable medium. There are no phase changes.

• The rock, liquids, and gas are incompressible.

• Except for surfactant adsorption, the fluids do not react with the rock.

• The phases attain steady-state mobilities immediately, dictated by saturations, fractional flows, and the presence or absence of adsorption.

• Viscous fingering and dispersion can be ignored.

• Initial conditions are uniform throughout the medium.

• A maximum of two mobile phases are present: a pure-gas phase and an aqueous phase, which contains water or water and surfactant.

• A maximum of three components are present in the two mobile phases: gas, water, and surfactant.

The fractional-flow function can be calculated from relative permeabilities and viscosities. The fractional-flow curve in the presence of foam consists of three regions, as shown in Fig. 1.

• In the strong-foam region, gas mobility is reduced greatly.

• In the region at the limiting capil-lary pressure—gas mobility varies, with almost no change in water saturation.

• In the weak- or broken-foam region, gas mobility is high.

Injection of a gas slug following a slug of surfactant in an SAG-foam process, as represented by fractional-flow theory, is shown in Fig. 2. For the first slug of gas, the initial condition of the reservoir is represented by Point I. The injection condition Point J is at zero fractional flow of water. There is a shock front from Point I to a point where it is tangent to

the fractional-flow curve at extremely low fractional flow of water, and a spread-ing wave from there to the injection condition Point I. Only this portion of the fractional-flow curve, and the total mobility along this portion of the curve, is important to a displacement in 1D. The total relative mobility of the initial state is relatively low because of the high viscos-ity of water compared to gas. The key to success of SAG-foam displacement is the strength of foam behind the shock front at very low fractional flow of water.

When a liquid slug follows foam, part of the gas injected in the previous slug is trapped. The initial condition for liq-uid injection is nonuniform, at a water saturation somewhere between connate-water saturation and the point of tangen-cy (Point J) as determined for injection of the first gas slug (Fig. 2). The relative mobility at residual-gas saturation is rela-tively low because of low relative perme-ability of water at these relatively high gas saturations and the high viscosity of water relative to gas. Therefore, liquid injectivity of a liquid slug following foam is lower than liquid injectivity of the first liquid slug. The fractional-flow model is only an approximate representation of liquid injection following foam, which can include liquid fingering, gas expan-sion, and gas dissolution, none of which are accounted for in the model.

Upon injection of the second gas slug, the initial state would be nonuni-form, but with relatively high gas satu-ration already present. The shock front is steeper than that shown in Fig. 2.

Idealized Model for SAG Displace-ment. On the basis of simulation results, it has been concluded that the ideal

SAG process shows high mobility near the injection well and low mobility at the foam front. SAG-foam processes can approximate this effect. Also, the pressure drop across a low-mobility dis-placement front in 1D cylindrical flow is constant in time as the front moves out-ward. An idealized model for SAG-foam displacements in homogeneous reser-voirs was constructed that predicts the shape and position of the foam front.

Although it is a simplified descrip-tion of the process, this model predicts several features seen in simulations of SAG processes.

• Constant-pressure SAG processes perform much better than constant-rate SAG processes with the same max-imum pressure.

• Constant-pressure processes yield good sweep, even when only a moder-ate pressure difference is applied.

• Details of foam properties play a relatively small role in sweep in a con-stant-injection-pressure SAG process. However, they do affect injection and production rates.

One assumption of the idealized model is that there is always enough surfactant ahead of the gas bank to sustain foam at the displacement front. In heterogeneous reservoirs, the foam front moves at different velocities in different layers, and crossflow may move gas to places in other layers with no surfactant present.

Optimal-Design Strategy Gravity overrides the results from com-petition between gravity (and density difference) and lateral-pressure gradi-ent. Gravity override also is promoted if the pressure gradient and velocity at the displacement front decrease as the dis-placement front moves away from the injection well, as it does in cylindrical flow at a fixed injection rate. Previous research contended that with relatively high mobility ahead of and behind the displacement front, a SAG process with fixed injection pressure could focus much of the pressure drop in the reser-voir at the displacement front to coun-teract gravity override. Therefore, a SAG process with fixed injection pressure yields better sweep efficiency in homo-geneous cylindrical reservoirs than a SAG process with fixed injection rate. A foam process with continuous foam injection performs even worse because most of the well-to-well pressure drop is dissipated in the near-well region.

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Fig. 2—Shock front for gas injection into a medium saturated with sur-factant solution.

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Further, a one-cycle SAG process can be better than multiple SAG cycles for cylindrical homogeneous reservoirs. Also, sweep efficiency depends primarily on injection pressure and is relatively insen-sitive to foam strength for fixed-pressure SAG processes. Foam strength does affect injection and production rates.

This study is part of a continuing effort to develop an optimal-design strategy for foam processes. The following strategy was developed on the basis of previous research on homogeneous reservoirs. This strategy is designed to lead to the optimal SAG process, subject to con-straints determined in Steps 1 through 3.

1. Determine the maximum allow-able injection pressure (e.g., avoid frac-turing the reservoir).

2. Determine the maximum allowable injection and production rates on the basis of the capacity of surface facilities.

3. Determine the desired process duration on the basis of economic fac-tors consistent with the allowable injec-tion and production rates.

Then, determine the best available foam formulation subject to those constraints by use of the following iterative process.

4. Choose a particular foam formula-tion, with properties measured in the laboratory. (In this study, this formulation is represented by a particular set of param-eters in the foam-simulation model.)

5. Assuming the goal is to sweep the entire formation, estimate the volume of foam required. Use fractional-flow theory to estimate the ratio of water- and gas-slug sizes that keeps surfactant ahead of gas throughout the process. In simula-tions with finite surfactant slugs, account for adsorption, as described in Appendix A of the full-length paper; a safety factor may be added to the estimated surfac-tant-slug size, to compensate for sur-factant slumping during gas injection. These steps give the total volumes of gas and surfactant solution to be injected.

6. Simulate the process with the given volumes and foam properties. If the pro-cess takes too long in the simulations, look for a weaker foam. If the process requires too high an injection or production rate, look for a foam with lower mobility behind the shock front in gas injection.

7. For homogeneous reservoirs, one big slug of surfactant followed by one big slug of gas yielded the best sweep efficiency. This prediction remains to be tested for heterogeneous reservoirs.

The authors were not able, in this initial study, to verify that the iterative

process of Step 6 yields the best sur-factant formulation, but they were able to test the effectiveness of SAG-foam processes in heterogeneous reservoirs and the sizing of the liquid slug accord-ing to Step 5.

For comparison with SAG-foam pro-cesses, they ran a limited set of simula-tions of water-alternating-gas (WAG) processes without foam. These pro-cesses and their results are described in Appendix B of the full-length paper. The full-length paper also details the simulation and parameters used, as well as the results of the simulation.

ConclusionsHomogeneous Reservoir.

1. Differences in sweep efficiency between fixed-pressure SAG processes and corresponding fixed-rate SAG pro-cesses are small in rectangular homoge-neous reservoirs. The higher the pressure or rate, the more vertical the foam front is. In fixed-rate SAG processes it takes longer to inject an equal amount of gas than in a fixed-pressure SAG process.

2. For gas injection into an infinite surfactant slug, the position and shape of the foam front is predicted accu-rately by the idealized model, despite the vertical variation in gas saturation behind the gas front.

3. Adjusting the size of the first sur-factant slug with a simple calculation can accommodate adsorption.

4. Injecting a large surfactant slug first helps to avoid gas breaking through the surfactant front. It also speeds the pro-cess, because liquid mobility is highest before gas injection and it reduces the time for segregation of gas during injec-tion of later surfactant slugs.

5. After injecting the first liquid and gas slugs in multiple-cycle SAG pro-cesses, injectivity decreases in every following slug. The more cycles used, the longer the time required to inject an equal volume of gas and surfactant solution. Longer times lead to greater gravity segregation during the process.

6. Both for one- and multiple-cycle SAG processes, sweep efficiency increas-es only slightly after gas breaks through in the homogeneous reservoir.

7. At gas breakthrough, a one-cycle, fixed-pressure SAG process has better sweep efficiency than multiple-cycle fixed-pressure SAG processes. One large slug of surfactant solution fol-lowed by one large slug of gas is better than use of multiple smaller slugs.

8. The ten-cycle, fixed-injection-pres-sure SAG process performs somewhat better than predicted by Stone’s model for continuous coinjection of gas and liquid at the same injection pressure.

9. SAG processes in the homoge-neous reservoir result in much better sweep efficiency than those obtained with WAG processes.

Heterogeneous (Layered) Reservoir. 1. In reservoirs with either a high-

permeability or a low-permeability layer at the top, injecting a large surfac-tant slug first to correct for adsorption throughout the process results in too much surfactant in the high-permeabil-ity layers, much of which is wasted.

2. A low-permeability layer at the bottom of a reservoir is barely swept, no matter the number of cycles, or duration, of the SAG process.

3. A low-permeability-layer at the top of a reservoir is swept only after a long time, long after gas breakthrough, and after the time at which the gas-produc-tion rate approximates the injection rate. Sweep efficiency at gas break-through is better in the reservoir with a high-permeability layer at the top than in the reservoir with a low-permeability layer at the top.

4. With the low-permeability layer on top, only a small amount of surfactant enters this layer at the injection well. Therefore, gas segregates rapidly in that layer and moves to the production well.

5. Even after gas breaks through in the low-permeability layer at the top, gas production remains low for a time and sweep efficiency still increases. After gas in the high-permeability lay-ers reaches the production well, sweep efficiency barely increases; the gas vol-ume produced is approximately the same as the volume injected.

6. In both types of heterogeneous reservoirs, gas breakthrough in a ten-cycle SAG process occurs later in time, but at less pore-volume injected, than in a five-cycle SAG process. However, sweep efficiency in both processes is approximately the same.

7. In both heterogeneous reservoirs, a one-cycle, maximum-fixed-pressure SAG process yielded the best sweep efficiency. One large slug of surfactant solution followed by one large slug of gas is best.

8. For both heterogeneous reservoirs, SAG processes result in much better sweep than WAG processes. JPT

Most of the mature waterflood projects in the San Jorge basin in Argentina have been affected by poor displace-ment and sweep efficiencies, both lim-iting recovery. A reactive-particulate system was tested to improve volumet-ric sweep efficiency. The main purpose of this field trial was to demonstrate the ability of the system to improve oil recovery by diversion of injected water into the poorly swept zones around the thief zone or streaks.

IntroductionThe Koluel Kaike and Piedra Clavada fields are at the southern flank of the San Jorge Gulf basin, in the province of Santa Cruz, Argentina. These fields were discovered in the early 1960s and were produced under primary deple-tion until the mid-1980s. Thereafter, a massive waterflood was initiated to increase the relatively poor primary recovery. The project has 220 injec-tors, with an average injection rate of 1,600 BWPD per injector, affecting 500 producing wells. A total of 1.9 bil-lion bbl of water has been injected, resulting in incremental recovery esti-mated at 75 million bbl of oil, through December 2006.

However, this mature waterflood, as with many other projects in the San Jorge basin, has experienced limited recovery. Poor displacement and sweep efficiency are characteristic of these reservoirs. The Koluel Kaike reservoir has an average of 15 stacked layers, which are braided channel deposits, each 16 ft thick.

Each channel is a differentiated flow unit, with individual gas/oil/water con-tacts, along a 3,000-ft column between 3,500 and 6,500 ft deep. Each channel is 700 to 2,300 ft wide, and they generally are not aligned vertically. In any given well, there is a series of separate layers for injection or production (flow prop-erties have a high degree of anisotropy). For both fields, more than 400 flow units can be differentiated.

Statistical estimation of the petrophys-ical properties indicates an average 22% porosity and 50- to 100-md permeability

for the matrix rocks. The mineralogy is complex and is derived from volcanic compounds and a wide range of clays and cementing materials. This varia-tion causes moderate complications in saturation determination from logs and/or causes formation-damage problems. There also is a wide range, and random variations, in the salinity of the relatively fresh formation water.

The reservoir fluid is undersaturated at initial conditions. The primary recov-ery mechanism is a combination of fluid and rock expansion. Oil gravity ranges from 19 to 23°API, viscosity from 5 to 150 cp at reservoir conditions (150°F), and gas/oil ratio from 30 to 100 scf/bbl.

Reservoir energy is limited, and production requires artificial lift. The productive layers are commingled in the wellbore, and the pump intake is set below the bottom productive per-

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 107923, “New Attempt in Improving Sweep Efficiency at the Mature Koluel Kaike and Piedra Clavada Waterflooding Projects of the S. Jorge Basin in Argentina,” by Pablo Adrian Paez Yañez, SPE, and Jorge Luis Mustoni, SPE, Pan American Energy; Maximo F. Relling, SPE, and Kin-Tai Chang, SPE, Nalco; and PaulHopkinson and Harry Frampton,SPE, BP, prepared for the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, 15–18 April.

Improving Sweep Efficiency at the Mature Koluel Kaike and Piedra Clavada Waterflooding Projects, Argentina

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Fig. 1—SEM photograph of a dried film of unreacted particles of the sweep-control reagent.


foration to maximize the drawdown. This configuration, with small annular space, precludes production logging and determining the production rate on a zone-by-zone basis. This limitation prevents determining individual-layer recovery factors.

Even though relative permeabil-ity and oil-viscosity data are scarce, at least on a zone-by-zone basis, it is inferred that a very unfavorable water/oil mobility ratio (2 to 30) exists. This

unfavorable mobility ratio resulted in early water breakthrough at producing wells. It is very unusual to encoun-ter evidence of oil-bank formation. A typical producer response to the waterflood is a simultaneous increase in the oil and water production with the water/oil ratio established rapidly at approximately 10. Response time at the waterflood producers is highly variable. A typical production increase at the affected producers begins 3 to 6

months after injection startup, and the magnitude also is highly variable.

The lack of per-layer reservoir data precludes deterministic calculation or a sophisticated numerical-simulation model. Values of certain parameters such as oil in place, recovery factors, and sweep efficiencies should be con-sidered as gross references and not as deterministic results.

Well CompletionOn average, each well intercepts six zones, ranging from 4 to 12 layers, that test oil; some of these require hydrau-lic-facture stimulation. Of the 500 pro-ducers, 56% are beam pumped, 42% are produced by use of an electrical submersible pump, and the remaining are produced by use of a progressing-cavity pump. Lifting optimization is accomplished by trying to maximize the drawdown by minimizing the bot-tomhole pressure. Typical production for a well under primary depletion is 30 BOPD with 30% water cut, while for a secondary producer, the average production is 20 BOPD with 97.5% water cut.

Reactive-Particulate SystemThe reactive-particulate system was proposed on the basis of simulation studies that showed deep flow diver-sion could achieve effective-sweep improvement in reservoirs having thief zones in full or partial contact with less-swept zones. Field trials in Alaska showed promising results.

Mechanism—Pore Scale. The par-ticulate system comprises submicron polymer-based particles having cross-links that break under the influence of heat. Unreacted particles are shown in the scanning-electron-microscope (SEM) photograph of a dried film of product in Fig. 1. As the cross-link-breakage reaction proceeds, the particles are able to imbibe water and swell such that they increase in size and then associate. The swollen associ-ated particles can block pore throats in matrix rock as shown in Fig. 2. In this sample, particles were allowed to react with deionized water, then the resultant mixture was dried and images were obtained. The fairly open network of 70 to 100 μm approximate-ly represents the probable maximum size obtainable. Under higher-salin-ity conditions, smaller though more structurally compact 10- to 30-μm

Fig. 2—SEM photograph of a swollen-particle network dried from deion-ized water showing extensive interparticle-network formation.

Fig. 3—SEM photograph of swollen-particle aggregates at higher salinity.

aggregates were obtained, as shown in Fig. 3.

The degree to which drying effects contributed to the aggregate size in these experiments is not known. However, permeability reductions of up to approximately 1.5 darcies seen in the laboratory and in field tests of porous media strongly support the formation of relatively large aggregates in solution.

Field TreatmentsThere are three phases of a treatment.

Injection. The submicron particles are mixed into the injection water with a surfactant to disperse efficiently as single particles. This process is sub-stantially easier for these particles than for the related linear water-soluble-emulsion polymers because the par-ticulates are crosslinked internally and do not swell or thicken the water as do water-soluble-emulsion polymers during mixing. The particles, dispersed in the injection water, travel down the well and follow the water into the rock matrix. The resistance to flow is minimal.

Propagation. Once in the matrix rock, particles follow the flow of the water. It appears unnecessary to know in detail how this flow occurs. The existence of thief-zone behavior indicates that a sweep problem exists, and the particles move in and with the water.

Popping. The injection water is often, though not always, cooler than the reservoir temperature, which results in the formation of a thermal front in the reservoir. Different grades of the particulate system have different reaction rates corresponding to given temperatures. Therefore, a product that reacts relatively slowly at injection tem-perature will react faster at reservoir temperature. Treatments for isother-mal targets with temperatures below approximately 200°F usually can be designed, but the use of a temperature difference in a field is preferred.

When the particles are heated, inter-nal crosslinks break and polymer par-ticles swell. Then, the particles are capable of interaction and can block pore throats.

Candidate-Screening CriteriaMany factors must be considered when ranking candidates for sweep improve-ment. The following points must be con-

sidered for potential sweep-improve-ment treatments with this system.

• Available moveable-oil reserves• Poor recovery results from limited

energy of the primary-recovery mecha-nism, poor displacement efficiency by secondary process, or poor volumetric-sweep efficiency caused by reservoir anisotropies (thief zones or channels)

• Moderate-to-low vertical-/horizontal-permeability ratio

• Relatively low injection-water tem-perature, enabling treatment to reach the thermal front in the reservoir

• Reservoir temperature• Injection-water salinity• Rock lithology and matrix perme-

ability• Well-pattern geometry and spacing• Injectivity• Ability to measure incremental oil• Surface-facilities availability

Field CaseInitial screening indicated that Pattern EV-142 would be suitable for treat-ment. The layer representing the majority of the original oil in place is Layer 152, although other layers were perforated in Injection Well EV-142. The recovery factor was 17% vs. the expected 30%. There was evidence of an adverse mobility ratio and evidence that the center of the channel sand in Layer 152 had been well swept, but the edges had not. The aim of the treatment was to divert water out of the main channel to recover unswept oil. The existence of unswept oil also was inferred from the incremental-oil response when production wells were converted to injectors.

Isolation of Layer 152 in EV-142. The sliding sleeves accessing the other perforated zones in the well were closed before the treatment. The layers that were closed in for the duration of the treatment were reopened a few days after conclusion of the treatment, thus allowing a comparison with the pretreatment production history.

Tracer Tests. The water-response times from the crossplot study did not suggest contact times less than 30 days. However, it was decided that a chemi-cal-tracer test be conducted. This test needed only to detect breakthrough times in the 30- to 60-day time peri-od because this period would require adjustment of the particulate-product choice and/or injection scheme. There

was no reported tracer response during the 105-day monitoring.

Polymer Selection. The location of the thermal front within the reservoir was not known or simulated; however, on the basis of previous experience, it was expected to be approximately halfway between the injection and first produc-ing wells. To avoid the possibility of particles being produced, it was con-sidered critical that the reaction time be shorter than the remaining transit time through the fastest connection between the wells. The medium reac-tion-rate grade was selected on the basis of water-injection temperature of 120°F, reservoir temperature of 160°F, injection-water salinity and pH, and the estimated minimum water-transit time from the injection well to the nearest production wells. A “popping time” at reservoir temperature was estimated at 40 days.

Concentration. The 50- to 300-md permeability range of the layer sug-gested particle concentration should be 3,000 ppm active, with the concentrate supplied as a 30% dispersion of particles in light mineral oil. This concentration allowed dispersion and dilution of the particle slug during the propagation phase of the treatment. It was expected that upon reaching the thermal front, the particle concentration would range from 2,000 to 2,500 ppm active.

ConclusionsTreatment of two waterflood projects in the San Jorge basin in late 2006 and early 2007 with a particulate sys-tem to improve sweep efficiency was evaluated and found applicable and of potential benefit. The means of target selection and treatment design were refined to cope with limited reser-voir and zonal-production informa-tion. This pilot test showed that the particulate sweep-improvement agent could be mixed and injected effec-tively in the oil fields of the San Jorge basin. The needed injection equipment was simple, and because of the cross-linked nature of the particles injected, the chemical-injection points could be closer together, with less intervening mixing than previously anticipated. The particles, mixed into the water, injected easily into sandstone matrix with permeability between 50 and 300 md, which is lower than that pre-viously field tested. JPT


The alkaline/surfactant/polymer (ASP) –flooding pilot tests in Daqing oil field commenced in 1982. Although the recovery rate can be improved by 20% over that with waterflooding, severe scaling formed in downhole equip-ment and in artificial-lift systems of ASP producers. Sucker-rod failure was extremely high for beam-pumping wells. The running life for progressing-cavity-pump (PCP) systems was longer but still not economical. Severe scal-ing on the surface of the pump and string was the major factor causing drastic oscillation of operating load. Stator-surface modification and fluid treatments increased the average run-ning life from several months to longer than 1 year.

IntroductionASP-flooding pilot tests commenced after waterflooding and indicated that the recovery rate was improved by 20% on average. However, a negative issue emerged: Severe scaling formed on the surface of production systems and resulted in abnormal operation.

In beam-pumping systems, when scaling particles dropped out and accu-mulated in the space between pump barrel and piston, the pump would be blocked in a short period. The

minimum running life was less than 1 month. In electrical-submearsible-pump systems, the main problem was motor failures resulting from separa-tors being blocked by scaling. The shortest running life was 1/2 month. The structure of PCPs resulted in a failure rate much lower than that of the other lifting methods. The average run-ning life was approximately 3 months. Fig. 1 shows some of the pump and rod abrasion problems.

PCP-Scaling Mechanism In the process of ASP flooding, alkaline lye reacts with rock minerals and for-mation water, increasing scaling-ions concentration (e.g., Ca2+, CO3

2−,SiO2

3−) in the formation. As produc-tion fluid moved close to or into the wells, the change of temperature and pressure breaks the balance of scal-ing ions and scaling forms near the wellbore, on the surface of downhole equipment, and on the inner surface of tubulars.

The study indicated that ASP scaling is a mixture of carbonate and silicate. The main mineralogical compositions are amorphous-state silicon dioxide, hexagonal-spherical calcite, and con-ventional calcite. Minor mineralogi-cal compositions are clastic quartz, clastic feldspar, clastic clay particles, and pyrite. The hardness of silicate is much higher than that of chromium coating, causing rotor-coating wear after a short period.

Rod Fatigue. PCP-well operating loads in the ASP-flooding area were less sta-ble than in other areas. Severe oscil-lation of the operating load resulted in a high rod-fatigue-failure rate in PCP wells in the ASP-flooding area. A study indicated that rod-fatigue failure resulted from the comprehensive influ-ence of several factors.

Friction Properties. In most cases, the friction factor of the stator/rotor interface is a constant in producing waterflooding or polymer-flooding liquid. With ASP fluid, the friction properties of the stator/rotor interface changed. Experiments showed that the friction factor between stator and rotor was irregular in ASP produced fluid, causing unstable operating loads in the ASP area.

Elastomer Effect. Nitrile butadiene rubber (NBR) is a viscoelastic material. That is, the elastomer deforms with the change in stress. Under the higher fric-tion force at the scaling interface, the elastomer’s elastic-lag effect would be much longer than under normal oper-ating conditions. If the friction force were high enough, the elastomer would “stick to” the rotor until its increasing elastic energy was high enough to over-come the viscous friction.

Rod-String Elastic-Lag Effect. The rod string’s elastic-lag effect decreased the rigidity of the whole system, which led to the larger operating-load-oscil-lation amplitude at the end of the polished rod than at the outlet of the pump. Severe rod-string oscil-lation resulted in PCP-rod failures in the ASP-flooding area. The severe rod oscillation also was caused by the larger interference fit of the pump and higher friction force because of scaling, special friction characteristics on the surface of the rotor and sta-tor resulting from scaling, and lower rigidity resulting from NBR viscoelas-ticity and rod-string elastic-lag effect.

PCP-Scaling SolutionsThe primary solution in ASP flooding was to reduce scaling in the downhole system. Several techniques have been tested and applied.

This article, written by Technology Editor Dennis Denney, contains high-lights of paper SPE 109165, “Technical Breakthrough in PCPs’ Scaling Issue of ASP Flooding in Daqing Oil Field,” byCao Gang, SPE, and Liu He, SPE, University of Science and Technology of China, and Shi Guochen, SPE,Wang Guoqing, Xiu Zhongwen, Ren Huaifeng, SPE, and Zhang Ying, Daqing Oilfield Company, pre-pared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November.

Pump-Scaling Issues in ASP Flooding in Daqing Oil Field

EOR/IOR



Surface Modification. Scaling tends to form on the surface of any mate-rial. The degree of scaling depends on the surface energy of the solid/liq-uid interface. Scaling particles deposit more easily on higher-surface-energy material than on lower-surface-energy material. The surface energy of chro-mium is much higher than that of NBR. Therefore, scaling on a chromi-um coating is more common than on the surface of elastomer. With a much lower surface energy than chromium, a ceramic-coated surface is less likely to have scaling than a chromium coating. Therefore, ceramic coating was chosen as the coating material.

As shown in Fig. 2, scaling particles on a ceramic-coated rotor were small and loose, while scale on the chro-mium coating was even and tight. The hardness of ceramic coating is much higher than that of chromium coating, which improves the antiwear property of rotor coating.

Optimum Interference-Fit Design. Interference fit is an important factor

determining PCP performance. It forms an effective seal between the rotor and stator of the pump, and it has a large effect on the operating load. If the inter-ference fit is too low, pump slippage increases, leading to low production rate and lift capacity. If the value is too high, the rod string sustains a higher operating load, which increases rod-failure risk.

In the ASP-flooding area, scaling on the surface of the rotor and stator increased the interference fit, which resulted in an extra operating load on the rotor and rod string. In this case, it is necessary to reduce the interference fit of the PCP.

Elastomer-Rigidity Adjustment. PCP performance in ASP flooding can be improved by increasing the rigidity of the elastomer. Experiments indicated that NBR with a higher rigidity had bet-ter fatigue performance than that with a lower rigidity.

Other Treatments. Other methods are being investigated to solve scaling

issues in ASP flooding. Stator-surface modification can eliminate scaling ten-dency. The key point is to determine the proper material, and stator-pro-cessing technology might be adjusted but could lead to extra investment. Use of a larger-diameter rod string or hollow rods could improve the rigidity of the system. This technique proved to decrease rod-failure rate but also increased the operating cost. An alter-native treatment was a scaling inhibi-tor that could eliminate scale or slow down the scaling process on the tubing and rod string. The injection point was below the pump.

ApplicationBeginning in early 2005, four PCP wells with ceramic-coated rotors, optimum interference-fit design, and adjusted-rigidity elastomer were tested in the first pilot-test area. At the time this paper was written, one well was still in operation, and the other three were changed because of the incompatible production rate. Results showed that the operating torque was lower and

Fig. 1—PCP-rotor and rod abrasion wear caused by scaling.

Fig. 2—Scanning electron micrograph of scale on chromium coating (left) and ceramic coating (right).



stable. No load oscillation and no rod-fatigue failures had been recorded. For the treated wells, no scaling and no wear were found on the rotor surface, as seen in Fig. 3. The average liquid displacement was 35.3 tonnes/d. The average pump efficiency was 66.2%. The average running life was 178 days, and the longest was 649 days.

In 2003, 43 ceramic-coated-rotor PCPs were put on production in three ASP-flooding pilot-test areas. The aver-age displacement was 126.8 tonnes/d,

and the average pump efficiency was 76.4%. The average running life was 416 days, while the longest running life reached 512 days.

ConclusionDecreasing the surface energy of the material is key to eliminating PCP scaling. A ceramic-coated rotor is a good choice. Its surface energy is much lower than that of a conventional chro-mium-coated rotor. Scale formed at a slower rate on ceramic-coated rotors

and could be wiped off in operation. The hardness of ceramic coating is much higher than that of chromium, which improves the antiwear perfor-mance of PCPs.

Optimizing the interference fit and adjusting elastomer rigidity also are important in improving PCP perfor-mance in the ASP-flooding area. For different ASP developing areas, the char-acter of artificial-lift issues might be dif-ferent. Treatments should be adjusted on the basis of an objective study. JPT

Fig. 3—Ceramic-coated rotor after 256 days of operation in Well X5 (left) and 170 days of operation in Well X6 (right).

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The Ghawar field in eastern Saudi Arabia contains carbonate reservoirs. Most wells in the field produce from the Arab-D reservoir, an Upper Jurassic limestone sealed by anhydrite. Oil pro-duction from the field started approxi-mately 55 years ago. Water injection started in the 1970s. A current evalu-ation of Arab-D wettability takes into account a long historical record of wet-tability measurements and production. The results of the original measure-ments have changed slightly, but they show a strong consistency 50 years later. Local variations in wettability indi-cating mixed wettability and oil-wet tendencies were observed when tar was present in a significant amount and in areas high on structure.

IntroductionThe wetting properties of carbonate res-ervoirs are fundamental to the under-standing of fluid flow in all aspects of oil production and can affect the pro-duction characteristics greatly during waterflooding. Therefore, knowledge of the preferential wettability of reser-voir rock is of utmost importance.

Carbonate reservoirs are heteroge-neous in nature because of the wide spectrum of environments in which carbonates are deposited and the subse-quent diagenetic alteration of the origi-nal rock fabric. These heterogeneities and the effects of wettability on residual-oil saturation, capillary pressure, electri-cal properties, relative permeability, and

oil recovery encouraged research to characterize and evaluate wettability of carbonate reservoirs. In the past, many engineers assumed that most reservoir rocks were water-wet. Recent work showed many carbonate reservoirs are oil-wet. Other studies have shown that the wettability of carbonate rocks is oil-wet, neutral, or mixed. This paper summarizes a study of wettability for the Arab-D carbonate reservoir (Upper Jurassic) in Saudi Arabia.

Arab-D ReservoirThe Arab-D reservoir was discovered in 1948. Five additional areas were identi-fied as parts of the Ghawar oil field. From north to south, they are Ain Dar, Shedgum, Uthmaniyah, Hawiyah, and Haradh. At the Arab-D level, the field is a north-northeast-trending composite anticline 230 km long by 30 km wide. The largest oil accumulations occur in

the lowest grainstone cycle of the Arab formation, the Arab-D reservoir. The vertical oil column has a maximum thickness of 1,300 ft. The oil-saturated interval extends approximately 250 ft below the anhydrite that separates the Arab-D reservoir from overlying Arab-C carbonate beds.

X-ray-diffraction and X-ray-fluores-cence analyses revealed that the most predominant mineral in the Arab D reservoir is calcite (80–100 wt%), while dolomite constitutes a second minor mineral (0–26 wt%), along with trace amounts (<5 wt%) of quartz, pyrite, ankerite, and halite.

Experimental ProcedureBefore 1970, Arab-D-reservoir cores were cut with high-pH, lime/starch/caustic drilling fluid. To evaluate the effect of drilling fluids on wettability, 69-lbm/ft3 brine and carboxymethyl

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105114, “Fifty Years of Wettability Measurements in the Arab-D Carbonate Reservoir,” by T.M. Okasha, SPE, J.J. Funk, SPE, and H.N. Al-Rashidi, SPE, Saudi Aramco, prepared for the 2007 SPE Middle East Oil & Gas Show and Conference, Bahrain, 11–14 March.

Fifty Years of Wettability Measurements in the Arab-D Carbonate Reservoir

EOR/IOR



0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

6,150 6,200 6,250 6,300 6,350 6,400 6,450

Sample Height Above OWC, ft

Wate

r W

ett

ab

ilit

y In

dex

Fig. 1—Relationship of wettability index to water and structural position.


cellulose (CMC)/bentonite/barite muds were used. The whole cores were immersed in water immediately after being removed from the core barrel. They were kept submerged in water until tested in the laboratory at the wellsite. Reservoir brine and dead oil were used as aqueous and oleic phases, respectively, in the static brine- and oil-imbibition tests.

After 1970, core material from the Arab-D carbonate reservoir was cut with a KCl brine and packed under deaerated KCl brine in plastic tubes. No chemical additive was used, mini-mizing possible alteration of the core wettability. Core plugs were drilled from the whole core at 0.5-ft intervals with brine identical to the preserv-ing brine. The drilling direction was perpendicular to the axis of the whole core. After trimming, the plugs were wrapped with aluminum foil and then placed in a sealed container completely submerged in evacuated KCl brine. Visual analysis, brine permeability at remaining oil saturation, and comput-ed-tomography scans were performed as screening tests to assist in sample selection. The screening tests were combined with a review of convention-al-core data and the geological descrip-tion of the core material to ensure that representative samples were tested. Cores that were fractured, broken, or displayed brine permeability less than

1 md were excluded from further test-ing. Wellhead oil from the Arab-D car-bonate reservoir at the three selected areas was used as the oleic phase in the wettability experiments [Amott, U.S. Bureau of Mines (USBM), and contact-angle methods], and recombined live oil at reservoir conditions (tempera-ture =190°F; pressure =2,500 psig) was used in relative permeability tests.

Synthetic brine was prepared on the basis of geochemical analysis of the produced water and was filtered through 0.2-μm filter paper. In addi-tion to sodium and chloride ions as the main components of the brine, divalent calcium and magnesium are also abundant.

Wettability measurements (quantita-tive methods) included the Carter Oil Company Research Method (1956), Amott method, and USBM method. For purposes of discussion, the wetta-bility-index range from −1 to +1 was subdivided and classified as follows: neutral or mixed-wet (−0.1 to +0.1), slightly water-wet (+0.1 to +0.3), water-wet (+0.3 to +1), slightly oil-wet (−0.1 to −0.3), and oil-wet (−0.3 to −1). Qualitative methods includ-ed the relative permeability method, the contact-angle method, and use of both the cryogenic scanning electron microscope (SEM) and environmental SEM to evaluate local wettability state within the pores.

ResultsQuantitative Methods (Amott and USBM Data). Wettability is a surface phenomenon. It is the tendency of one fluid to spread on or adhere to a rock surface in the presence of another immiscible fluid. Wettability has a sig-nificant effect on oil recovery result-ing from waterfloods or by waterdrive mechanisms. Therefore, it is necessary to determine preferential wettability of the reservoir, whether it is to water, oil, or somewhere between the two extremes.

Uthmaniyah Area. Results of the Carter Oil Company Research Method measurements indicated that the tested plugs ranged from neutral to slight-ly water-wet, with wettability indices between −0.1 and +0.1. It was stated that the high-pH, lime/starch/caustic drilling fluid has a slight tendency to make the rock surfaces more water-wet.

A 69-lbm/ft3 brine and a CMC/bentonite/barite mud were used. Wettability data showed that both drilling fluids had an insignificant-to-minor effect on changes of wettability. Data also showed insignificant changes in wettability as a result of preserva-tion with distilled water in glass jars for 5 months. Therefore, core samples could be preserved and wettability tests could be made under controlled laboratory conditions with proper pre-cautions taken in coring and preserv-ing samples.

In the early 1990s, Amott wettabil-ity indices for Well UTMN-A core material varied between 0.03 and 0.68, while for Well UTMN-B, they ranged from 0.2 to 0.41. Core materials recov-ered from Wells UTMN-A, -B, -C, and -D were neutral to slightly water-wet. Preserved core plugs from Wells UTMN-E, UTMN-F, and UTMN-G were tested for wettability by use of the USBM method. The results indicated a general trend of neutral to slightly oil-wet behavior. However, samples from below the oil/water contact (OWC) demonstrate a neutral to slightly water-wet behavior.

Hawiyah Area. Two wells from the Hawiyah area (Wells HWYH-A and HWYH-B) were tested by use of the Amott and USBM methods. Samples tested from Well HWYH-A were from a lower depth than those selected from Well HWYH-B. Well HWYH-A showed a general trend of neutral to slightly water-wet characteristics. USBM indices ranged from −0.4 to 0.1, while Amott

82

80

Fig. 2—Appearance of water distribution and neutral wetting character-istics of grains of Arab-D carbonate rock.

indices varied between 0.03 and 0.35. Well HWYH-B showed that core plugs had oil-wet, to neutral, to slightly water-wet character. USBM indices ranged from −0.38 to −0.62, while Amott indi-ces varied between 0.07 and 0.37.

Three additional wells (HWYH-C, HWYH-D, and HWYH-E) were tested with the Amott method. Data indicated that the tested pugs showed neutral to slightly water-wet character, with a ten-dency of increasing water-wet behav-ior with depth. Unlike samples in the UTMN area, samples in HWYH below the OWC showed strongly water-wet character. Amott wettability indices ranged from 0.0 to 0.87.

Haradh Area. Four wells from the Haradh area were tested by use of the Amott method. Wettability indices var-ied between −0.02 and 0.68. The results revealed that the tested core material had neutral to slightly water-wet to water-wet characteristics, with a tendency for increased water-wet characteristics with depth. Samples from below the OWC showed stronger water-wet character than those above the OWC.

Discussion. Fig. 1 shows that the wettability index to water for Arab-D reservoir decreases as the sample height above the OWC increases. Samples close to the OWC are water-wet, whereas intermediate wettability is obtained high above the OWC.

Overall, core material of the Jurassic Arab-D carbonate reservoir tends to be neutral to slightly water-wet in the absence of systematic variations and in the absence of strong oil-property changes. Stronger oil-wet tendencies, particularly below the OWC, also can be attributed to the close proximity of the UTMN tar mat. Variations also may be related to the variation of rock fabric, facies, and environment of depo-sition, which result in variation of pore-size distribution. In relation to position on structure, the combined historical data for the Arab-D confirm that wet-tability variation of carbonate reservoirs shows increasing water-wet character below the OWC.

Qualitative Methods (Amott and USBM Data). Relative Permeability.Many waterflooding experiments were conducted to generate relative perme-ability curves for the Arab-D reservoir in the three areas. All measurements were taken on composites of three or four core plugs. Composites are used

because they are least affected by core-scale heterogeneities. They provide more-precise data because the pore volume and pressure drop both are larger and are less affected by capillary and inlet-end effects. Results of oil/water relative permeability tests indi-cated that oil recovery ranged from 26 to 45% at breakthrough and reached an ultimate recovery in the range of 46 to 62% of the original oil in place. The residual-oil saturation varied between 39 and 45% of pore volume at the end of waterflooding. The relative perme-ability results suggested a slightly oil-wetting core material.

Contact Angle. Contact angle is a measure of the intrinsic wettability of a reservoir rock. It ranged from 0 to 180°. When the contact angle is less than 60°, the surface is referred to as water-wet, and when it is greater than 120°, the surface is considered oil-wet. A neutral system has contact angle ranging from 60 to 120°.

Contact-angle values at room temper-ature ranged between 40 and 43°. At res-ervoir conditions, they varied between 50 and 53°. These results showed slight-

ly water-wet behavior for the Arab-D crude-oil/brine/calcite system under measurement conditions. A 1992 study showed that receding contact angle for the Arab-D-crude-oil/brine/Arab-D-rock-material system ranged from 100 to 105° (temperature =70°C; pressure =50 psig), indicating neutral character. On the basis of the variation of contact angle and hysteresis caused by surface roughness, the obtained contact-angle data can be used only for rapid qualita-tive screening of trends, but under no circumstances should generalizations be made with respect to the systems of fluids in rocks.

Microscopic Observations. Fig. 2 shows the water distribution on a rock sample as received and flushed with synthetic brine (similar to reservoir brine). The contact angle is approxi-mately 80°, which reflects a neutral character of the tested sample. A cryo-genic-SEM study conducted on Arab-D rock material indicated that both oil and brine were either filling or lining the pore walls. This observation sug-gested the existence of a mixed-wet-tability system. JPT

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