development of mature oil fields

ngineering 57 (2007) 221–246www.elsevier.com/locate/petrol

Journal of Petroleum Science and E

Development of mature oil fields — A review

Tayfun Babadagli

Department of Civil and Environmental Engineering, School of Mining and Petroleum, University of Alberta, 3-112 Markin CNRL-NREF Building,Edmonton, AB, Canada T6G 2W2

Received 23 May 2006; received in revised form 11 October 2006; accepted 12 October 2006

Abstract

Development of mature oil fields has been, and will increasingly be, an attractive subject. Mature field development practices can bedivided into twomajor groups: (1) well engineering and (2) reservoir engineering. This paper focuses on the reservoir engineering aspects.

An extensive review of previously reported reservoir management practices for mature field development is provided. After thedefinition of mature field and an overview, different aspects of mature field development are outlined. The first issue covered is theestimation of remaining reserves focusing on the determination of the amount and location of the residual oil after primary andsecondary recovery using field, log, and core data. After valuing the remaining oil, methods to recover it are classified. Theyinclude tertiary recovery, infill drilling, horizontals, optimal waterflooding design for mature fields, optimal well placement andother reservoir management practices. Suggested or implemented field application examples for big fields owned by majors andsmall fields owned by independents are presented.

Special attention is given to tertiary oil recovery. An extensive review and critical analysis of tertiary recovery techniquescovering the theoretical, practical, and economical aspects of it are provided. The emphasis is on their applicability in mature fielddevelopment in terms of effectiveness (incremental recovery) and efficiency (cost and recovery time). Laboratory and field scaleapplications of different tertiary recovery techniques, i.e., gas (double displacement, WAG, and miscible–immiscible HC, CO2, andN2), chemical (dilute surfactant, polymer, and micellar injection), and thermal (air and steam) injection, conducted to developmature fields are included. Specific examples of big/giant fields, fields producing for decades, and mid to small size fields wereselected. Differences in reservoir management strategies for majors, independents, and national oil companies are discussed.© 2006 Elsevier B.V. All rights reserved.

Keywords: Mature fields; Remaining oil; Residual oil saturation; Tertiary oil recovery; Reservoir management techniques

Contents

1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2222. Definition and elements of mature field development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2223. How much oil is left and where is the remaining oil? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2234. Techniques used to determine the amount of remaining oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223

4.1. Core analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2234.2. Logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2234.3. Volumetric-reservoir engineering studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225

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222 T. Babadagli / Journal of Petroleum Science and Engineering 57 (2007) 221–246

4.4. Production data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2254.5. Well testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2254.6. Chemical tracers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2254.7. Field experiences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226

5. Tertiary recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2285.1. Laboratory scale investigations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 228

5.1.1. Non-fractured rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2285.1.2. Immiscible gas injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 228

5.2. Miscible gas injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2295.3. Air injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2305.4. Chemical injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2305.5. Fractured rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231

6. Field scale applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2337. Reservoir management practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2348. Well placement, infill drilling, horizontal wells and optimizing waterflooding . . . . . . . . . . . . . . . . . . . . 2399. Concluding remarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 240Nomenclature. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 241Acknowledgment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 241References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 241

Fig. 1. Different stages of oil recovery that can be assumed as thestarting of the maturity of a field. Typical tendency is the periodindicated by the arrow.

1. Introduction

The world average of oil recovery factor is estimatedto be 35%. Additional recovery over this “easy oil”depends on the availability of proper technologies,economic viability, and effective reservoir managementstrategies. On the other hand, the chance of discoveringgiant fields remarkably decreases (Blaskovich, 2000).The discovery rate for the giant fields peaked in the late1960s and early 1970s and declined remarkably in thelast two decades (Ivanhoe, 1997). About thirty giantfields comprise half of the world's oil reserves and mostof them are categorized as mature field. The develop-ment of those fields entails new and economically viabletechniques, and proper reservoir management strategies(Black and LaFrance, 1998; Al-Attar, 2004).

Mature field development is a broad subject. It can,however, be divided into two main parts: (1) welldevelopment, and (2) reservoir development. Dependingon the field type, history, and prospects, the developmentplans could be done on either one or both. This papercovers reservoir engineering aspects of mature fielddevelopment. Determination of the amount and locationof the remaining oil is the key issue in this exercise.Techniques to improve the recovery factor such as tertiaryrecovery, infills, horizontals, and optimal placement of thenewwells are the other elements of reservoir development.

2. Definition and elements ofmature field development

Oil fields after a certain production period are calledmature fields. A more specific definition of mature

fields is the fields reaching the peak of their productionor producing fields in declining mode. A third definitioncould be the fields reaching their economic limit afterprimary and secondary recovery efforts. Fig. 1 shows atypical production life of a field. Any points indicated bya question mark can be considered as the time when thematurity is reached. The tendency, however, is to definethe decline period indicated by the arrow in Fig. 1, whichis typically reached after having some secondary re-covery efforts. Increasing water and gas production,decreasing pressure, and aging equipment are other in-dicators of maturity.

Technologies to revitalize mature oil fields are basedon either well or reservoir applications. Once the maxi-mum number of wells that can possibly be applicable tothe field is reached, well development practices such as

Table 1Logs used to determine residual oil saturation

Log type Technique Cased hole Accuracy

Resistivity Conventional N PoorPulsed neutron Log-inject-log Y GoodNuclear

magnetismConventional N Poor

Carbon/Oxygen Log-inject-log Y Good

223T. Babadagli / Journal of Petroleum Science and Engineering 57 (2007) 221–246

recompletion, stimulation, treatments, optimization oflift, re-collection of data, surveillance, and new entriesare considered. Next, injectors for pressure maintenanceor displacement are drilled mainly targeting secondary ortertiary recovery. For any of those practices, one needs toknow the amount and location of the target oil first. Re-booking the reserves for such cases has always been achallenge due to uncertainties and difficulties in theestimation of residual oil saturation (Ross, 1998).Therefore, the first issue to tackle in mature field devel-opment is to quantify the amount of oil left. Obviously,the next step is to quantify the recoverable amountaccurately and find out the tools/methods to achieve this.It is critical to decide when to start these applications tomaximize the ultimate recovery of oil. This is an im-portant issue especially for tertiary recovery applicationsif the company is concerned with the ultimate recoveryrather than accelerating the production rate in short term.

Efficiency is the key issue in mature field develop-ment. The cost of the project increases while the revenuegained from additional oil recovery decreases as a fieldages. This is obviously the disadvantageous part of thepractice. On the other hand, having a great deal of in-formation about the field, experience, and data gatheredover the years is the advantageous part of it.

In the following sections, we discuss the reservoirengineering aspects of mature field development andreview the possible techniques and applications on howmuch recoverable oil there is, how fast it can be re-covered, and how cost efficient it would be.

3. Howmuch oil is left and where is the remaining oil?

Determination of the amount of residual oil satura-tion after primary and secondary recovery processes is achallenge. Locating the oil to be recovered is a difficultexercise and requires sophisticated techniques as well.Egbogah provided an extensive review of those tech-niques (Egbogah, 1994). Volumetric reservoir engineer-ing studies and core analysis are the tools to be used forthe amount of the remaining oil but not the distributionof it. Tracer tests orwell testmethods are used to determinethe location and distribution of the remaining oil.

4. Techniques used to determine the amount ofremaining oil

4.1. Core analysis

Fluid saturation of virgin or waterflooded cores aredetermined by distillation (water saturation) and extraction(oil saturation) using solvents. It has been recognized thatrelating oil saturation to in situ values is a serious problem.Special core analysis (SCAL) increases the accuracy of theestimation as it represents realistic reservoir conditions(pressure, temperature, and wettability) but it is costlycompared to conventional core analysis (Wyman, 1976).The residual oil saturation obtained from core analysis maynot be representative for the whole reservoir as thedisplacement is not controlled only by microscopic factorsat the field scale. The following equation proposed byKazemi (1977) is used to estimate the residual oil saturationat reservoir scale using core residual oil saturation:

PSoð Þres¼

PSoð ÞcoreBoE

M1� V 2

ð1Þ

4.2. Logs

Resistivity, pulsed neutron capture, nuclearmagnetism,carbon/oxygen, and gamma radiation logs are used todetermine the residual oil saturation. Both conventional orlog-inject-log applications are possible for some of theselogs. Table 1 lists the application types, advantages, anddisadvantages of each logging technique.

Water saturation from resistivity logs can be calculatedusing the following equation introduced by Waxman andSmits for shaly sands,which is amodified formofArchie'sclassic equation (Waxman and Thomas, 1968).

Sw ¼ Ro

Rt

1þ RwBQV

1þ RwBQV

Sw

!1n

24

35 ð2Þ

where B is defined as follows:

B ¼ 0:046ð1� 0:6eCw=0:013Þ ð3Þ

Fig. 2. Effect of clay content on the hydrocarbon saturationwhenEq. (2) isused to calculate it (re-plotted using the data provided in Al-Kharusi,unpublished).


cw is the reciprocal of Rw. The oil saturation is estimatedusing So=1−Sw. This relationship is commonly used forthe conventional applications of resistivity logs as well as afew others such as Simandoux and Fertl and Hammackequations.

The same types of logs are used for log-inject-logapplications as well. In this process, oil bearing for-mation is logged to obtain the Rt first. A solvent is theninjected to remove oil. Finally, brine is injected to mea-sure the Ro. The oil saturation is calculated using thefollowing relationship:

So ¼ 1� Ro

Rt

� �1n

ð4Þ

Both conventional and log-inject-log applications areused only in open holes. The accuracy of the saturationexponent, n is vital in the estimation of the remaining oil(or reserves). Due to the empirical nature of this quan-tity, the use of resistivity logs in the saturation estima-tion has always been questionable. Small changes in thisexponent may result in significant variations in thereserves obtained by volumetric calculations. Variabilityof the saturation exponent in the reservoir caused by theclay content and pore structure is another factor affect-ing the accuracy of the reserves estimation (Worthingtonand Pallatt, 1992).

The termQV in Eq. (2) is also critical in the estimationof the amount of remaining oil. In many applications,misinterpretation of the logs due to lesser amounts ofclay considered in the system causes underestimation ofthe amount of oil. In an unpublished study, Al-Kharusi(unpublished) found the QV value to be 0.4 for asandstone reservoir in Oman containing different typesof clays (ankerite, chlorite, koalinite, and illite) bymultiple salinity technique using the following equation:

Co ¼ 1FðBQV þ CwÞ ð5Þ

The plot of Cw vs. Co yielded QV. Previous ex-perience for this field had shown that the QV=0.1.Those values of QV as well as the case of QV=0 werecompared in Fig. 2. Significant changes in the oilsaturation values were observed with an increase in theQV. Incorrect estimation of the amount of clay orelectrically conductive minerals results in an under-estimated value of hydrocarbon saturation (Cook et al.,2000).

Pulsed neutron capture (PNC) log can be used in log-inject-log applications for both open and cased holes

with high accuracy. The following equation is applied toestimate the remaining oil saturation:

Sor ¼ 1� ðRt2 � Rt1Þ/ðRw2 � Rw1Þ ð6Þ

where Σt1 and Σt2 , and Σw1 and Σw2 are the capturecross sections of the formation and water measuredbefore and after the injection, respectively.

A more accurate technique was proposed later usingnuclear magnetism log. This techniques detects hydro-gen in the water and oil and applicable as inject-log.Water containing paramagnetic ions is injected into theformation and the Free Flow Index (IFflow) of oil isdirectly or computationally obtained. Then, the follow-ing equation is applied to estimate the remaining oilsaturation:

Sor ¼ IFflow/

ð7Þ

This technique is applicable only in open holes.Another log type used to determine the remaining oilsaturation is the carbon-oxygen (C/O) log, which detectscarbon (exists in HC) and oxygen (exists in water). It is


similar to the PNC and a gamma ray detector. Theremaining oil saturation is estimated using the followingequation:

So ¼ C=Olog � C=O100%water

C=O100%oil � C=O100%waterð8Þ

The gamma radiation log is another log type used forlog-inject-log applications. In this process, water withradioactive tracer is injected before and after removal ofresidual oil.

Lately, Hlebszevitsch et al. (2003) and Gutierrez et al.(2001) reported synthetic sonic log and cased-hole log-ging applications to assess the remaining oil saturation inmature oil fields.

4.3. Volumetric-reservoir engineering studies

The remaining oil saturation is obtained by the fol-lowing equation if the total amount of oil in place (Nfoi)and the cumulative oil produced to the end of water-flooding (Np) is known:

Sor ¼ ðN � NpÞBoWF

7758Ah/ð9Þ

Prediction of Np is a critical task. One of the tech-niques used for this is the material balance equation:

Np ¼ NfoiðBt � BtiÞ þ ðWi �WpBwÞ þ GiBg

ðRp � RsÞBg þ Bo

þBti

ð1�SwiÞ ½ðCf þ SwiCwÞDP� þ mBtiBgi

ðBg � BgiÞ þWe

ðRp � RsÞBg þ Bo

ð10Þ

The material balance calculations based on this equa-tion yield reliable results for the volumetric reservoirs.

4.4. Production data

Production history plot is another reliable source toestimate the final production (Np). Graphical (Arps,1945) and analytical (Fetkovich, 1987) techniques canbe applied to forecast the production data.

When multiphase production occurs from a well, thesaturations can be estimated using the production re-lative permeability data. The relative permeability ratiocan be obtained using

krwkro

¼ qwBwlwqoBolo

¼ WORBwlwBolo

ð11Þ

if the flow rates are known. Oil saturation can be calc-ulated by dividing the current reservoir volume of the oilby the current pore volume:

So ¼ Vo

Vp¼ ðNfoi � NpÞBo

NfoiBoið1� cfDPÞ=ð1� SwiÞ ð12Þ

Dependency on the real (measured) production datamakes these techniques reliable compared to the labora-tory measurements.

4.5. Well testing

Permeability and relative permeabilities can be ob-tained from pressure transient data. If the relative perme-ability measurement through core analysis is available,one can obtain the saturations using the relative perme-ability data. In addition, saturation can be estimatedthrough the following relationship if there is no free gasin the system (Ramey, 1975).

So ¼ ct � cw � cfco � cw

ð13Þ

cf, co, and cw are the pore volume, water, and oilcompressibilities, respectively. The total compressibility,ct, can be obtained from pressure transient analysis usingthe following relationship (Earlougher, 1977):

ct ¼ 0:0002637ðk=lÞt/r2

DtMðtD=r2DÞM

ð14Þ

where the (k /μ)t is the total mobility defined as

kl

� �t

¼ kolo

� �þ kw

lw

� �þ kg

lg

!ð15Þ

ΔtM and (tD / rD2 )M are the time and dimensionless time

values obtained from the type curve analysis. There arealso analytical and numerical modeling techniques toestimate the waterflood performances but the accuracy ofthe models strictly rely on the estimation of the Sor (orrelative permeabilities), which is based on core analysis.

4.6. Chemical tracers

When a chemical tracer is injected, its molecules arelocally distributed between water and oil in the reservoir(Tomich et al., 1973). At the equilibrium, the thermody-namic equilibrium ratio, Ki is obtained as follows:

ðCiÞoilðCiÞwater

¼ Ki ð16Þ


The value of Ki can be measured in the laboratory.The molecules of tracer i will move with a characteristicvelocity that depends on the fraction of time that themolecules spend in each phase. If the probability offinding a typical imolecule in the water phase is pi, thenthe expected velocity of i molecule is

Vi ¼ piVw þ ð1� piÞVo ð17ÞEq. (17) can be written in terms of the saturations as

follows:

Vi ¼ ð1� SoÞVw þ KiSoVo

ð1� SoÞ þ KiSoð18Þ

The velocities are obtained from field experimentsand the Ki is measured in the laboratory (Eq. (16)). Atthe residual oil saturation, oil velocity is zero. Whenbrine containing a tracer with known distribution co-efficient, Ki is injected and the time for arrival to anotherwell is measured, one can obtain the residual oil satu-ration using

Vi ¼ ð1� SorÞVw

ð1� SorÞ þ KiSorð19Þ

Recently, Huseby et al. (2003) provided an experi-mental and numerical technique to estimate the locationand the size of bypassed and stagnant oil using geo-chemical data from produced oil and water.

Five techniques are used for residual oil saturationdetermination as discussed above. Techniques such asresistivity logs, nuclear magnetism logs and core analysisrequire new wells drilled. Pulsed neutron logs and che-mical tracer methods can be applied to old cased wells.

Elkins (1978) compiled the residual oil saturationvalues obtainedbydifferent techniques for different forma-tions in the US. Figs. 3 and 4 show the comparison ofdifferent techniques. Based on this evaluation, the fol-lowing conclusions can be reached regarding the residualoil saturation (ROS) measurements:

• ROS (core, log, tracer)bROS (Material Balance)• ROS (PNC)=ROS (Resistivity logs)• ROS (Single well tracer)b (ROS (logs)

4.7. Field experiences

A challenging case of determination of remaining oilsaturation was reported by Akkurt et al. (2000). Themature fractured-vuggy carbonate Yates field hasundergone many different EOR applications. Significant

variations in n (saturation exponent) andm (cementationfactor, between 1 and 5), yielding inaccurate estimationof water saturation from Eq. (3), were observed with thatfield. It was also observed that the n changes with spaceand time and the surfactants used in the field altered thewettability of the rock. Also, borehole was filled withgas and electromagnetic propagation tools do not workin gas. Therefore, NMR, which is insensitive to gas, wassuggested to measure the residual oil saturation. NMR(limited to the invasion zone with a few inches depth ofinvestigation) is an alternative to resistivity saturation.Oil and water can be identified by exploiting the dif-fusion coefficient (Do) contrast between them in NMRapplications. They compared the old resistivity satura-tion measurements to the new values obtained from theNMR and noted that the resistivity based model is com-plex and requires a substantial level of petrophysicalexpertise to implement while the NMR approach is re-latively simpler.

Verma et al. (1991) compared residual oil saturationsobtained through special core analysis (SCAL), log-inject-log, Thermal Decay Time (TDT) log, and materialbalance for a carbonate reservoir. The values variedbetween 5 and 40% for the field and 14 and 56% for thelab measurements. The average value they found was23.2%. They concluded that the most reliable resultswere obtained from the SCAL with preserved cores.Log-inject-log yielded reasonably good results while thematerial balance provided a good cross check. They alsoobserved a strong dependency of residual oil saturationafter waterflood (SORW) on Swi and proposed the fol-lowing correlation between these two quantities.

SORW ¼ 0:06ð1� SwÞ/

ð20Þ

Elkins (1972) observed that the cores acquired fromunconsolidated sands may result in overestimation ofporosity and therefore the OOIP. They measured theporosity from cores to be 39% through conventionalcore analysis. The SCAL resulted in much lowerporosity (31%), which is in agreement with the logporosities. They concluded that the actual oil recoveryefficiencies by waterflooding may have been muchhigher than those reported. Hence, oil remaining inplace as a target for tertiary recovery may be much lessthan what was estimated by conventional methods ofdetermining porosity and subtracting cumulative oilproduction. Later Elkins and Poppe (1973) evaluated afield case to estimate the residual oil saturation left forthe tertiary oil recovery. They reported that the reductionin porosity due to compaction should be recognized

Fig. 3. Comparison of the residual oil saturations obtained through different techniques for sandstones (plotted using the data provided in Elkins,1978).


and pressure coring is important in the evaluation ofunconsolidated field cases. Peripheral waterfloodingresidual oil saturation for this field was less than pre-dicted (Sor being not more than 25%) leaving this field amarginal field for prospect tertiary oil recovery.

Tchambaz (2004) presented a new formation resis-tivity tool for the cased holes to measure the watersaturation in water injected zone as an alternative tonuclear logging (TDT), which did not showed reliable

Fig. 4. Comparison of the residual oil saturations obtained through different1978).

answers for a layered sandstone and a carbonate field inLibya due to low salinity. He was successful in pointingthe location and amount of remaining oil (unswept bywater injected) comparing the first (uncased hole) andthe latest (cased hole, four years later) resistivitymeasurements.

Another cased hole resistivity log measurement wasreported by Hupp et al. (2002). They proposed thefollowing equation as depletion indicator. Using this

techniques for carbonates (plotted using the data provided in Elkins,


equation they located undepleted (or unswept) zones forfurther treatment.

CHFR� Depletion� Indicator ¼ffiffiffiffiffiffiffiffiffiffiffiffiRt�CH

Rt�OH

rð21Þ

where CH and OH denote the cased and open hole,respectively. In addition to the resistivity application in thecased hole, nuclear logging has been commonly applied todetermine the location and the amount of the remaining oil.For nuclear logging, saturation monitoring through casingis performed in two ways: (1) decay of thermal neutronpopulations (TDT), and (2) relative amounts of carbon andoxygen by inelastic gamma ray spectrometry (as used inthe Induced Gamma Ray Spectrometry tool—GST). TheTDT provided better results in highly saline formationwaters. One should select the TDT and GST or com-bination depending on the salinity contrast and the level ofsalinity (Schlumberger Wireline and Testing, 1993).

5. Tertiary recovery

The tertiary recovery aspects of mature field devel-opment will be evaluated for laboratory and field scaledevelopments. Taber et al. (1997a,b) classified differentenhanced (tertiary) oil recovery (EOR) techniques andtheir selection criteria. In this section, the focus will beon those tertiary recovery techniques typically appliedafter massive water injection for pressure maintenanceor displacement. Therefore, the tertiary recovery of oilinvolves in the displacement of oil in an environmentwith excessive amount of water, in some cases oc-cupying more pore space than oil within the rock. Thisrequires a clear understanding of the immiscible andmiscible displacement of residual oil while anothermobile phase exists as well as the three-phase relativepermeability concept. Jones (1985) observed that the timerequired for a fluid particle to traverse a porous mediumdepends on rock topology and fluid distribution. Oilrecovery by a miscible hydrocarbon (HC) solvent may bequite incomplete when another phase (water) exists in thesystem. HC can invade only the more accessible waterfilled pores (high IFT between water and HC). He alsonoted that the mixing zone is long in a water-wet core. HCentrance into water filled small-pores takes time (over-coming the capillary entry pressure). Oil may not be dis-placed from the smaller pores.

5.1. Laboratory scale investigations

Fractured and non-fractured systems will be evalu-ated separately in this section. The applications of

immiscible (double displacement methods and inert gas)and miscible (hydrocarbon gases and carbon dioxide)gas injection, chemical injection (mainly surfactantsolutions), and air injection as tertiary recovery agentswill be reviewed.

5.1.1. Non-fractured rocksTertiary recovery applications largely studied at la-

boratory scale are immiscible and miscible gas injection,chemical injection (surfactant, alkaline, and micellarsolutions), and air injection. Steam injection for tertiaryrecovery is quite uncommon and it is mainly applied as asecondary (or even primary) displacement method inheavy-oil reservoirs.

5.1.2. Immiscible gas injectionOren et al. (1992) studied the mobilization of residual

oil by immiscible gas injection under water-wet con-ditions using micro models. They observed that the re-coveries for positive spreading systems are much higherthan for negative systems when the spreading coeffi-cient, Sow is defined as follows:

Sow ¼ rwg � rog � row ð22Þ

They also noted that the oil is displaced by a double-drainage mechanism (gas/oil and oil/water interfacemovement) for both positive and negative spreadingsystems and gas/water displacement is possible for ne-gative spreading systems.

Kantzas et al. (1998a,b) studied downward displace-ment of oil by inert gas (nitrogen or air) injected at thetop of the formation using horizontal wells after water-flooding. They observed that the gravity assisted inertgas injection has a potential to become an efficient EORmethod with up to 99% of remaining oil recovery fromunconsolidated samples. Later, Lepski et al. (1996)showed that when the spreading coefficient (Eq. (22)) ispositive, oil tends to spread on water and form a con-tinuous film. When it is negative, the residual oil tendsto coalesce and form blobs occupying several porespaces. They observed that if the gas injection process isstopped after breakthrough and the system is shut off fora few days and then water is injected, significant oilproduction is obtained. The process of displacing the oilbank by secondary waterflooding was named SecondContact Water Displacement (SCWD).

Recently, Righi et al. (2004) showed that immisciblewater-alternating-gas (WAG) in watered-out coresyielded additional recovery. They observed that addi-tional 28% of the remaining oil could be recovered after57% OOIP waterflooding recovery by immiscible WAG


from original sandstone reservoir cores with 18% po-rosity and 25–300 mD permeability.

Babadagli et al. (2001) tested nitrogen injectionpossibility to a tight unswept (as a secondary recoverymethod) and high permeability watered-out sandstone (as atertiary recovery method) containing light-oil. The onlymechanism tested was the immiscible displacement of oilby an inert gas. Secondary nitrogen recovery wasmeasured to be 36–42% OOIP from 1 to 5 mD sandstonecores. The tertiary recovery from 200 to 300mD sandstonerock with 70%–75% previous waterflood recovery was 6–8% OOIP. High injection pressures were required in thisdeep reservoir (3500m) to overcome the reservoir pressureand miscibility and double displacement are the otherpossible recovery mechanisms to contribute to therecovery at this pressure. Technical success did notguarantee that the project would be economically viableas will be discussed in the field case evaluations later.

5.2. Miscible gas injection

Typically HC gases (CH4 or liquefied petroleumgases [LPG]), N2 and CO2 are used as tertiary recoveryagents. They are all multiple contact miscible except theLPG. Above the minimum miscibility pressure (MMP),the recovery would increase significantly. The miscibleresidual oil saturation (Sorm) is a key property for si-mulation studies of gas injection. Typically, the capillarynumber is used to determine the residual oil saturation.This requires correct measurement of the IFT betweenequilibrated phases. Lange (1998) observed that themiscible and near-miscible residual oil saturation, Sormis a function of solubility parameters. They developedthe following correlation using the tertiary recovery ofeight different crude oils in carbonate and sandstonecores with EOR gases:

Sorm ¼ 0:036ðjdoil � dgjÞ � 0:029 ð23ÞThe solubility parameters for crude oil and gas

(Gidding et al., 1968) are defined as follows:

doil ¼ 0:01⁎M þ 6:54� 0:01⁎ðT � 25Þ ð24Þ

dg ¼ 0:326ðPcÞ0:5ðqr=qrðliqÞÞ ð25Þ

where M is oil average molecular weight and T is tem-perature. ρr(liq) is the reduced density of the gas com-pressed to a liquid state.

In many applications, the process might take place atpressures slightly below the MMP because of the vari-ation or reduction in the pressure. This pressure range thatdoes not develop complete miscibility is called near-

miscible zone. In this case, the recovery might besignificantly (negatively) affected. Eq. (23) covers bothmiscible and near miscible conditions. Other factor thatmight be effective on the recovery at near miscible pres-sure is the amount of existing water saturation. Wylie andMohanty (1996) reported that in the presence of water,vertical mass transfer increases with gas solvent enrich-ment and the mass transfer is reduced in the presence ofwater while the reduction is less as capillarity increases.They also observed that the near-miscible gas floods donot appear to be influenced by water saturation level.

Kasraie and Farouq Ali (1984) studied the effect ofsecond immobile phase on the dispersion duringmiscible flooding. They observed that the dispersionin a porous medium tends to decrease in the presence ofwetting immobile phase. The opposite was observedwhen the immobile phase is non-wetting. They alsoshowed that the mixing coefficients are lower when animmobile aqueous phase was present.

Shyeh-Yung (1991) studied decane/CO2/brine systemwith Berea sandstone at near-miscible pressure range. Heshowed that the tertiary oil recovery by CO2 floodlinearly decreases by decreasing pressure and CO2

mobility decreases with decreasing pressure near misci-ble conditions. He also observed that the secondary CO2

flood could recover more oil than tertiary CO2 flood.One of the critical aspects of miscible flooding is the

effective use of WAG process. The optimization of thisprocess has been studied extensively in the past. Jacksonet al. (1985) observed that the optimum slug sizes are0:1 (continuous slug process) and 1:1 for tertiary oilrecovery by CO2 injection for water-wet and oil-wetsystems, respectively. They noted that maximumrecovery is a stronger function of slug size in secondaryCO2 flood than in tertiary flooding. Tertiary floods in thewater-wet models were dominated by gravity forceswhile tertiary floods in an oil-wet medium were con-trolled by viscous fingering. The effect of wettability onthe performance of WAG is crucial, especially at highWAG ratios (Stern, 1991). High WAG ratios result inless oil recovery by extraction. In water-wet rocks, thiseffect is significant and no extraction at high WAGratios is observed. In mixed-wet rocks, however, signi-ficant oil recovery is obtained due to extraction regard-less of WAG ratio.

Another critical aspect of WAG injection is to deter-mine the best injection strategies to maximize the re-covery. Srivastava et al. (1995) observed that thesecondary slug flood had the highest recovery efficiencyamong the three possible injection strategies (secondaryslug, tertiary slug, and tertiary WAG) for the recovery of14 °API-heavy-oil. They also pointed out that the tertiary


WAG produced higher oil recovery than the tertiary slug.Determination of the best strategy for the most efficientdisplacement and minimum residual oil saturation is animportant issue inmature field development. Skipping thesecondary (waterflooding) recovery and starting directlyslug gas injection yielded much more efficient recoveryespecially for live oil.

Krizmanic (2004a) reported optimumWAG injectionschemes for mature fields in Croatia and evaluated thetrapped gas saturation and waterflood residual oilsaturation for those cases (Krizmanic, 2004b).

5.3. Air injection

Although steam is not a favorable tertiary recoveryagent, air injection has been found an efficient one due toits lower cost. Sakthikumar et al. (1995) compared theperformances of tertiary injection (after waterflooding)of N2 and air injection into limestone and sandstonesamples containing light oil. Their laboratory experi-ments showed that the air injection recovery was 46.4%whereas N2 injection yielded 43.2% oil recovery. Fassihiet al. (1997) reported a field trial conducted uponsuccessful laboratory tests of air injection into light oilreservoirs for tertiary recovery. They reported up to 14–16% OOIP incremental recovery from the field applica-tion after 5–15% primary recovery. Fassihi and Gillham(1993) tested the DDP (double displacement process)potential of air injection in the watered-out mature WestHackberry field. They observed that the combustion willoccur at reservoir conditions and reservoir has sufficientreservoir temperature to accelerate oxygen consumption.

5.4. Chemical injection

The most common chemical injection technique as atertiary oil recovery method is surfactant solution injec-tion due to its relatively lower cost compared to themicellar or microemulsion injection. Michels et al. (1996)tested the tertiary recovery potential of a low concentra-tion (0.1 wt.%) anionic surfactant. The tests on Bereasandstone samples showed that 78% of the remaining oilafter waterflooding was recovered with the injection of2.3 PVof surfactant solution. They also used a sacrificialagent to minimize the surfactant retention and observ-ed that an optimal value of the sacrificial agent exists.Using the residual oil saturation value of 27.5% obtainedfrom core experiments, additional 9% OOIP recovery in30 years was targeted. The efficiency and economics ofthe project were tested for different optimal injectionoperational plans. A different rock type (cleaned chalksamples from the cores of the Yibal field in Oman) was

exposed to a similar tests by Babadagli et al. (2002).Many different surfactant types were tested as tertiaryrecovery agents at different concentrations after massivewaterflooding. An extra oil recovery of 0% to 7.5% wasobtained after waterflooding, which yielded an averagerecovery value of 75% OOIP. The surfactant solutioninjection into virgin core samples resulted in an averagevalue of 69% recovery, which was substantially lowerthan that of waterflooding. This was attributed to the re-tention of surfactant during the flood in chalky limestonesamples. They concluded that surfactant concentrationand type play a primary role in the tertiary recovery of oil.

Another surfactant injection into light oil (33–35 °API)sandstone reservoir was reported by Zaitoun et al. (2003).Low concentration anionic surfactant solutions were in-jected into high salinity core samples to formulate the fieldinjection plan. They observed 36% OOIP recovery afterwaterflooding.

Clark et al. (1988) studied the performance of acosurfactant enhanced polymer flood (alkaline–surfac-tant–polymer) in Berea sandstone. An average of 23%OOIP incremental recovery was obtained after 36%waterflooding recovery with different formulations.

Microbial injection has been also proposed as a ter-tiary recovery (Almeida et al., 2004) as well as waterconformance (Stepp et al., 1996) technique to developmature oil fields.

Obviously, laboratory scale work is needed toformulate the optimal design of any tertiary injectionproject. Especially, the estimation of the incremental oilrecovery and compatibility of the recovery agent with therock, oil and formation water are two essential factors tobe determined from the laboratory scale tests. Field scalesimulations are needed for further performance estima-tion. The following are the key issues to be considered inthese practices:

• The right time to start tertiary oil recovery. Theamount of – immobile – water from secondaryrecovery might significantly affect the efficiency oftertiary recovery.

• Injection strategy to be followed (slug sizes are cri-tical not only for the technical success but also for theeconomical viability of the project).

• Optimal injection scheme.• The ultimate goal (is it faster – accelerated – recoveryor higher ultimate recovery?). The company size andlong-term policies are critical in this decision and themature field development plan through enhanced oilrecovery should be determined based on the short-mid-and long-term plans of the companies. This will bediscussed later in the Field scale applications section.


The laboratory experiments provide answers to thesequestions partly. Upscaling this information to fieldcases is an important issue (Christman and Gorell,1990). It is highly difficult to determine the economicsof the project from the laboratory tests without fieldscale simulation study but the laboratory data provide aninsight into the residual oil saturation.

5.5. Fractured rocks

Main recovery mechanism from NFR involvesmatrix–fracture interaction due to capillary, gravity, andviscous forces as well as mass transfer. Significant efforthas been devoted to the primary and secondary recoveryfrom matrix since the 1950s. Morrow and Mason (2001)and Babadagli (2003a) provided a review of the primaryand secondary matrix recovery mechanisms. Tertiaryrecovery of matrix oil requires more efforts towards theunderstanding the physics of the process.

Three types of agents have been tested in the labora-tory environment for tertiary recovery of oil from thematrix. They are namely hot water or steam, surfactantsolutions and miscible fluids (solvents).

Babadagli (2001) exposed sandstone and limestonecores to static (capillary) brine imbibition first and thenhot water. It was observed that starting the process withwater and continuing with hot water (up to 90°C) wouldyield higher ultimate recovery than exposing the core tolow IFT surfactant solutions from the beginning. Water+hot water combination could potentially be moreeconomic than chemical injection for water-wet samples.Depending on the matrix interaction type (co- or countercurrent) determined by the matrix boundary conditions(all sides open matrix or matrix partially exposed towater imbibition), hot water imbibition following waterimbibition showed different recovery performances. Ifthe oil is recovered from a matrix that is not open to flowfrom all sides, the oil recovery is not only due to thermalexpansion but also enhanced imbibition or even gravitydrainage for sandstone (strongly water-wet) rocks.Recovery after waterflooding from a rock sample allsides open to flow could be limited to thermal expansionof oil only. If unfavorable matrix boundary conditionsexist, hot water injection after fully completed waterinjection is a technically successful process.

Guo et al. (1998) exposed the siltstone core plugs,obtained from the Spraberry Trend Area and saturatedwith original reservoir oil (∼1 cp), exposed to waterimbibition. They observed that starting the experimentat room temperature would not yield any imbibitionrecovery whereas experiments conducted at 138F fromthe beginning showed 20–25% OOIP recovery. This is

above the recovery that could possibly be recovered bythermal expansion (Briggs et al., 1992; Babadagli,1996). Other mechanisms, such as augmented capillaryimbibition by reduced interfacial tension and changes inthe wettability, contributed to the recovery. When thetemperature is increased from the room temperature thatresulted in no recovery, 7–9% OOIP oil recovery wasobtained. This is typically the recovery by thermal ex-pansion. Therefore, starting the process with hot water isa technically more feasible than starting with water fol-lowed by hot water injection.

Sahuquet and Ferrier (1982) tested the performanceof secondary and tertiary (water injection followed bysteam) steam injection into fractured dolomitic carbon-ate rock from the Lacq Superieur field. The dominatingrecovery mechanism was capillary imbibition. Oilviscosity was 17.5 cp. Water imbibition at 60 °C yielded15% OOIP recovery. Steam injection at 150 °C fol-lowing the water injection gave additional 14% reco-very. When the process is started as steam injection at290 °C, the total recovery reached 70% OOIP with amuch faster recovery rate than the lower temperatureexperiment. Hallenbeck et al. (1991) performed similarexperiments on North Sea Chalk (Ekofisk field) samplesusing 33 °API original crude oil. They observed 32%OOIP recovery by water imbibition at room tempera-ture. When the experiment was continued at increasedpressure and temperature (300 psi and 270F), theyobtained additional 14% OOIP recovery. This was acorrected value to thermal expansion. Therefore, theadditional recovery is mainly due to enhanced capillaryimbibition as well as other potential matrix-fracture in-teraction processes except expansion.

It can be concluded that it is reasonable to start withhot water or steam injection rather than waterflooding inweakly water-wet systems for a faster recovery and lessresidual matrix oil saturation. For strongly water-wetsystems, however, the hot water injection after water-flooding would yield mainly thermal expansion ofresidual-waterflood-oil. Note that starting the processwith hot water injection would yield the same ultimaterecovery but faster recovery rate (Babadagli, 2002).

Dilute surfactant injection studies were also conductedfor tertiary recovery. Babadagli (2003b) observed no ca-pillary imbibition recovery from Berea sandstone matrixwith different non-ionic surfactant solutions after brineimbibition that yielded 45–60% OOIP recovery. He usedmineral and light crude oil. Cuiec et al. (1994) obtainedadditional 20% OOIP recovery with lowered IFT usingsurfactant solutions (1.5 mN/m) after brine (41 mN/m)imbibition recovery of 52% OOIP on chalk samplessaturated with n-C6.

Table 2Primary brine, and secondary and tertiary surfactant solution imbibitionrecoveries from dolomite (data from Standnes and Austad, 2003)

Coreno.

Primary rec.with brine(% OOIP)at 70 °C

Additionalsecondary rec.with C10 NH2

(% OOIP) at 70 °C

Additional tertiaryrec. with C10 NH2

(% OOIP)at 20 °C

k(mD)

1 15 28 5 222 8 5 57 3523 7 1 44 101


Standnes and Austad (2000) tested the capillaryimbibition recovery on dolomitic samples. Without anysurfactant addition, no recovery was obtained after ex-posing the rock to brine for several weeks. When a 1 wt.%cationic surfactant was added to the brine, 60% of OOIPwas recovered. This amount corresponds to the recoveryobtained from the capillary imbibition experiments startedwith the same surfactant solution. Experiments on oil-wetwest Texas carbonates showed that only 4% OOIP oil isrecovered by brine imbibition (Standnes et al., 2002).Addition of an anionic surfactant (ethoxylated alcohol)yielded an additional 3%OOIP recovery. When a cationicsurfactant (C12 TAB, 3.5 wt.% — below CMC) is usedinstead of the anionic one, 40% OOIP additional recoverywas obtained. Nearly-oil-wet chalk samples showed 12%OOIP primary oil recovery with brine imbibition (Austadand Milter, 1997). When the same cationic surfactant wasadded at 1 wt.% concentration, 30% OOIP incrementaloil recovery was obtained. If the same experiment isstarted with the surfactant solution (C12 TAB), 65%OOIP is recovered at a much higher rate. Later, Austadand Standnes (2003) observed that dolomitic oil-wetreservoir rocks yielded no capillary imbibition recoverywith brine. If the experiment is continued with a 1%cationic surfactant (C12 TAB), nearly 60% OOIP re-covery was achieved. When the same surfactant solutionwas used without exposing the rock to the brineimbibition first, the same recovery was reached at fasterrecovery rate. They also observed that the performance ofan anionic surfactant with dolomitic oil-wet samples wasmuch lower (35% of OOIP) than that of cationic sur-factants (65% of OOIP). Standnes and Austad (2003) alsotested C12TAB on the dolomitic samples exposed ini-tially to a complete brine imbibition at 20 °C and 70 °C.Initial brine and secondary surfactant solution imbibitionrecoveries are summarized in Table 2. This indicatessignificant tertiary recovery potential of capillary imbibi-tion when the injected water is replaced by low IFT(surfactant added) water. It should be noted, however, thatstarting the injection with surfactant solution might bemore economical considering the increasing recovery rateas well as potentially higher ultimate recovery.

In a similar attempt, Xie et al. (1998) performedcapillary imbibition experiments on the cores obtainedfrom shallow-shelf carbonate reservoirs. Field produc-tion performance showed a recovery of less than 10%OOIP. Brine imbibition recovery was obtained between0% and 35% OOIP. Imbibition recoveries of a cationic(cocoalkyltrimethyl ammonium chloride — 0.3 mN/m)and a non-ionic (ethoxylated alcohol–poly oxyethylenealcohol— 2 mN/m) surfactant solutions were then testedon the cores exposed primarily to brine imbibition.

All surfactants were around the CMC (low concen-tration). Additional 5%–15% OOIP recovery wasobtained mainly due to improved imbibition driven bywettability change. They also tested the effect of initialwater saturation on the performance and observed thatthe existence of initial water saturation causes higherultimate recovery from the surfactant solution imbibi-tion. The existence (Weisbord et al., 2002; Babadagli,2003c) and amount (Li et al., 2002) of initial watersaturation are critical on the recovery and there would beconsiderable amount of water left from primary andsecondary recovery applications in the matrix. Theseobservations showed that additional recovery with sur-factant solutions is a possibility after completed imbi-bition recovery with brine. The amount depends on therock type and selection of compatible surfactant type.Especially, the tertiary recovery potential of surfactantsolution in carbonates is significant.

A few studies on the tertiary recovery from matrix bysolvent injection were reported. Hatiboglu and Baba-dagli (2004) tested the recovery potential of solvent (n-heptane) diffusion on Berea sandstone cores exposed tocomplete brine imbibition. They obtained 42%–55%OOIP co- and counter-current capillary imbibition re-covery with brine for different matrix shape factor (lengthto diameter ratio). Additional solvent (n-heptane) recov-ery by diffusion followed by the capillary imbibitionvaried between 2% and 20% OOIP depending on thematrix shape factor. When the same cores were exposedto the solvent diffusion without primary water imbibition,the ultimate recovery was obtained as much higher thanthe total of primary imbibition and secondary solventdiffusion for all cases. When the total recovery time wasconsidered in the process, the imbibition followed by thediffusion scheme yielded more efficient process. It isobvious that this would be an economically favorableprocess as well. When a similar process was repeatedusing Indiana limestone (less water-wet sample thanBerea sandstone), the diffusion process turned out to bemore favorable as the imbibition recovery is not as


effective as in the water-wet sandstone case (Hatibogluand Babadagli, 2005), especially for heavier oils.

Svec and Grigg (2000) studied the additional re-covery potential of CO2 injection into pre-waterfloodedfractured core samples from the Blinebry formation (NewMexico). Three mixed- and oil-wet samples yielded 17%,41%, and 51%OOIPprimary recovery fromwaterflooding(mainly imbibition). When the same samples were ex-posed to CO2 injection, 40%, 35%, and 32% OOIP addi-tional recoveries were obtained, respectively.

Hamida and Babadagli reported that tertiary (Hamidaand Babadagli, 2005a) and secondary (Hamida andBabadagli, 2005b) capillary imbibition oil recoverypotential under ultrasonic radiation exists for sandstone(strongly water-wet) and carbonate (weakly water-wet)rocks exposed to primary water imbibition. The labora-tory scale recovery potential and mechanisms are yet tobe clarified for the tertiary recovery potential of theultrasonic waves. Field scale applications need furthertechnological development for this relatively less costtechnique.

In summary, water injection continued by chemical,thermal or solvent injection is an efficient process forstrongly water-wet and light oil systems. But, if there is nocapillary imbibition potential like carbonate rocks andheavy-oil cases, it is reasonable to start the project with thetertiary recovery agents such as steam/hot water, surfac-tant solutions, or solvents rather than waterfloodingwhichyields a remarkably slow capillary imbibition recovery orgravity drainage.

Field trials of the applications outlined above arelimited and the economic viability of these applicationsis a concern mainly due to early breakthrough riskcaused by fractures. Experimental studies are the onlysolutions for the assessment of the recovery potential ofthe tertiary recovery applications outlined above as thenumerical models are yet limited to do this due to dif-ficulties in modeling matrix–fracture interactions andrepresenting the complex fracture networks.

6. Field scale applications

Despite their technical feasibility (effectiveness) asdiscussed in the previous sections, in many circum-stances, the economics of tertiary recovery field ap-plications does not permit to choose this option as amature field development plan. Careful analysis of eco-nomic feasibility (efficiency) of the tertiary recoveryapplications (mainly thermal, chemical, and solventinjection due to their high CAPEX and OPEX) is neededwith minimized uncertainty (McCarthy et al., 1981;Baviere et al., 1994; Suguchev et al., 1999). The advan-

tageous part of the development of mature fields throughtertiary oil recovery is the data, information and ex-perience gathered throughout the production life thatwould significantly minimize the geological or technicaluncertainties. The uncertainty in oil prices is the majorfactor that affects the applications of tertiary recoveryprojects (Taber et al., 1997b; Stosur, 2003). The followingpoints should be taken into consideration during theplanning of a tertiary recovery application to develop amature field:

• The effectiveness of the project, i.e., the total incre-mental oil recovery by tertiary methods.

• The efficiency of the process: Total cost/total recovery.In the secondary recovery applications, the expectedultimate recovery is generally higher and the total costof the project is lower than those of tertiary recoveryapplications. Blackwell (1978) stated that the tertiaryrecovery economics is sensitive to the remaining oil.Precise knowledge of the distribution of the remainingoil is a critical prerequisite in selection, design andevaluation of any tertiary recovery application. There-fore, the amount of target oil and the reserves should bedefined accurately. Although an error of 10% PV in theremaining oil saturation can be tolerated in primary andsecondary recovery decisions, an error as small as 5%PV can lead to economic failures in tertiary oil re-covery. Blackwell concluded that a 1% change in theestimation of the remaining oil (or target oil for tertiaryrecovery) might lead to a 1.5% increase or decrease inthe rate of return. Schumacher (1980) evaluated 136field cases of tertiary oil recovery applications. Heobserved that the gas injection projects (CO2 andmiscible gas) had the highest amount of remaining oilsaturation (73%–85%). The second tertiary recoverytechniquewas the thermalmethods (in-situ combustionand steam injection) averaging a value of 65% residualoil saturation in the beginning of the project. Forchemical methods (surfactant and polymer injection),the residual oil saturations varied between 37% and54%.

• Recovery time and management strategies for dif-ferent size companies: Depending on the companysize, the mature field development strategies throughtertiary oil recovery change. Due to high risk factors,small companies avoid investment-intensive long-term projects. They mainly pay attention to the fasterrecovery rather than ultimate recovery. Big sizecompanies may target higher ultimate recovery asthey can afford long-term investments. This will bediscussed with two field examples in the Reservoirmanagement practices section later.


The sample field cases selected to represent differenttertiary recovery methods and field types are summa-rized in Tables 3, 4 and 5, for gas, chemical, and thermalinjection applications, respectively. The most commontertiary recovery application item is obviously the gas(miscible or immiscible) injection. All the applicationslisted in Table 3 were performed after certain degrees ofwaterflooding. The projects were all successful withsome incremental oil. The sweep efficiency is related toWAG ratios. The economics of the project is also con-trolled by the WAG ratio as it reduces the amount ofexpensive tertiary recovery gas. Winzinger et al. (1991)tested the effect of different WAG ratios on the incre-mental recovery for CO2 injection. They observed that0:1 (continuous CO2) and 1:1 WAG ratios yielded simi-lar tertiary oil recovery (14–16%) from the carbonatecore samples of the North Ward Estes field. Due to thecost of the project, 1:1 ratio turned out to be optimumratio. 2:1 WAG ratio yielded 13% recovery. This ratio isto be determined by the core flood tests before the fieldtrials. In the “Comments” column of Table 3, the coreresults were added if there were any.

Likewise, the slug sizes are important in optimizingthe chemical injection processes (Table 4) (Fathi andRamirez, 1984, 1986). Continuous injection of chemi-cals might cause higher cost and/or lower sweep andtherefore, injection of the agents as slugs is necessary foran efficient process. Thomas et al. (1990) injectedmicellar slugs into waterflooded Berea samples with35% residual oil saturation. A linear relationship bet-ween the slug size (PV) and tertiary oil recovery (%OOIP)was observed. Higher amount of oil and surfactant con-centration in the micellar (oil+water+surfactant+IPA)resulted in higher recovery up to 45% of the residual oil(with 10 PV slugs).

Continuous injection of low surfactant concentrationsolution was also observed as an effective process.Maerker and Gale (1992) conducted surfactant solutionexperiments on sandstone samples. The residual oil (5–7 cp) saturation after waterflooding was between 30%and 38% OOIP. The recovery by surfactant solutioninjection varied between 20% and 75% of the residualoil. Babadagli et al. (2002) reported results for a similaroil with chalk samples. The average waterfloodingsaturation was 75% of OOIP. The tertiary recovery withdifferent type surfactant solutions yielded additional0%–7.5% OOIP.

Wyatt et al.'s (2004) radial core flood tests resulted inadditional 9% OOIP recovery by polymer flood afterwaterflooding which recovered 30% OOIP from a sand-stone sample. In another attempt, they obtained 52%OOIP recovery from the waterflooding and additional

20% OOIP recovery from the following polymer flood(Wyatt et al., 2002). Alkaline–polymer mixture yieldedadditional 26% OOIP recovery after a waterfloodingperformance that resulted in 48% OOIP recovery.

All these attempts were needed to assess the fieldperformance and the economics of the projects. Theestimation of the optimum chemical concentrations andslug sizes aswell as the chemical retention ismainly basedon these types of laboratory tests (Barua et al., 1986;Jakobsen and Hovland, 1994; Baviere et al., 1994).

Tertiary recovery attempts using thermal techniqueswere not common as inferred by Table 5. Excessive costlimits their use to develop mature fields depleted tosecondary residual oil saturation. Sakthikumar et al.(1995) performed waterflooding test on a sandstonesample saturated with light oil and obtained 58% OOIPrecovery. A subsequent air injection yielded additional5.7% OOIP recovery. Recoveries lower than water-flooding performancewere obtainedwhen air was injectedinto a virgin core.

Babadagli et al. (2001) searched the possibility of airinjection instead of more expensive nitrogen for tertiaryrecovery of light oil from a sandstone reservoir. Due toits low cost and higher recovery potential (by thermaleffects), air injection has turned out to be a more favor-able tertiary recovery method for a small size company.However, its potential danger in the production wellscaused by the unconsumed oxygen and pressure re-quired to inject the air into deep formation limit its usefor this light oil sandstone reservoir. Steam injection istypically secondary or even primary recovery agent,which is more useful for heavy-oil reservoirs, rather thantertiary recovery in mature fields due to its high cost(Schumacher, 1980).

7. Reservoir management practices

In addition to tertiary oil recovery applications, othertypes of reservoir management practices to developmature oil fields were also proposed and implemented.They include data acquisition/analysis campaigns forreservoir simulation to re-evaluate the remainingreserves (Murty and Al-Haddad, 2003; Mijnssen et al.,2003) or revisiting/recompletion the wells (Pang andFaehrmann, 1993), re-engineering using classic reser-voir engineering analysis techniques and clustering thewells based on their performances (Coste and Valois,2000; Marquez et al., 2001). Another cost effectivereservoir development practice was to improve thevolumetric sweep efficiency through the realignment ofthe injection and production wells (Zambrano et al.,1992). Surveillance of the secondary and tertiary

Table 3A summary of tertiary gas injection applications reported

Field(discovery year)

OOIP Injected fluid(year started)

Formation type/permeability

μoil/°API Recovery history(starting year)

Primary andsecondary recovery

Incremental tertiaryrecovery

Comments Ref.

Slaughter Estate Unit(1937)

0.65 MMstb Miscible acidgas-(1976) pilot

Carbonate 6.4 mD 1.38 cp WF (1972), AG (1976),CG (1978) WF (1982)

18% OOIP79 15% OOIP80

(95,680 stb)Schiltz et al., 1984;Rowe et al., 1982

Twofreds (Delaware)Unit (1957)

51 MM stb CO2 (1974)field scale

Sandstone 32 mD 1.5 cp WF (1963) CO2 (1974) 16.4 % OOIP(prim.+sec.)

Significant recoverywas observed

Incremental rec. wasdifficult to determine

Schiltz et al., 1984

Weyburn (1956) 1.4 billion bbl Misc. CO2 (2000)field scale

Fractured carbonate1–100 mD

0.5 cp WF (1960s) Ult. sec. rec. 25–35% 10% OOIP (estimated) Baker and Kuppe, 2000

Ekofisk (1969) 6.7 billion bbl Miscible nitrogen Highly fracturedchalk 0.1–10(matrix) 200 (fracture)

33 °API WF (1986) pilot(Ekofisk form.) full field(Tor form.)

24% OOIP (Pr. andgas inj.) 5.5% OOIP (WF)

Under consideration 2.5–61% OOIP WFrecovery from lab tests

Thomas et al., 1991

North Ward Estes(1929)

1.1 billion bbl CO2 (1989) field scale Sandstone/siltstone 15 mD

14 cp 37 °API WF (1955) 38.7 % OOIP 4.3% OOIP Opt. WAG=1:1, opt.slug size: 38–60% PV

Ring and Smith, 1995

North Ward Estes(1929)

CO2 — foam(1989) field scale

Some incrementalrec. observed

Heterogeneous res.(poor sweep)

Chou et al., 1992

Handil (1975) 0.3 billion OOIP Lean gas (immiscible)field scale (1995)

Sandstone 10–2000 mD 0.6–1 cp31–34 °API

Peripheralwater injection

58% OOIP (in 1.5of the field)

1.2% OOIP (3 yr inj.) 7.4%(next 20 yr)

Core flooding: 27% WF,3% tertiary

Gunawan and Caie, 2001

Kelly-Snyder (1948) 2.11 MM bbl CO2 — WAG (1972)full field

Limestone 20 mD 0.35 cp Centerline WF (1954) Earlier est.: 23% OOIPlater est. 8% OOIP

CO2 — WAG 6% HCPV CO2

and 2.8% HCPV waterKane, 1999

South Ward (1933) 8.8 MM bbl Propane slug (misc.)pilot (1961)

Sandstone 40–300 mD 3.4 cp WF (1950) 16% OOIP (primary) 47%OOIP (secondary)

37,000 bbl in ∼2 years ROS after WF: 18.7% (core)19.3% (volum.) 19.6 (logs)

Blanton et al., 1970

Phegly Unit (1955) 9.6 MM bbl LPG slug (1964)full field

Sandstone 0.6–610 mD —ave: 168 mD

2.3 cp WF 5-spot pattern (1959) Pr. 21.4% OOIP Se. 20%OOIP (1959–1964)

3.4% OOIP(1964 and 1971)

ROS after WF: 25% Connally, 1972

Mitsue Gilwood Unit(1964)

770 MM bbl Solution gas enrichedwith LPG

Sandstone 64–250 mD Peripheral waterinjection (1968)

Pr.: 1.7% OOIP Se. (WF):45% OOIP

Estimated 12.2% OOIP Core data: 58%WF+26–36% solvent

Frimodig et al., 1988

Brookhaven (1943) Gas+water (1965)full field

Sandstone 56 mD 26–40 °API Gas injection (1948)water–gasproduced (1957)

5 MM bbl (halfof the residual oil)

Meltzer, 1974

Little Creek (1958) 102 MM stb CO2 full field (quarter9-spot) (1974)

Sandstone 33 mD 0.4 cp Peripheral waterinjection (1962–1970)

Pr.+Se.: 54% OOIP(21% OOIP by WF)

Pilot: 122,200 bblsbetween 1973 and 77

Hansen, 1977

Jay/LEC (1970) 728 MM bbl Miscible N2 (1981) Deep carbonate 3 mD 0.18 cp WF (1974) Target was 346–373 MMbbl (51% OOIP)

Target: 47 MM bbl(6.5% OOIP)

2.9% OOIP (1981 and 8492)2 MM bbl (1984)93 7–10%OOIP (2002)94

Christian et al., 1981;Langston and Shirer, 1983;Lawrence et al., 2002

Garber (1916) CO2 5-spotpilot (1981)

Limestone 47 °API WF (1948) 84 MM bbl (prim.and second)

70,000 bbl (1984)11% OOIP in pilot area

Core: WF: 24–35% CO2: 2–21% (with increasing pressure)

Kumar and Eibeck, 1984

Offshore Abu Dhabi Immiscible gas (1997)full field

Carbonate Initial target 2% OOIP Lab: 17% OOIP tertiaryimmisc. gas inj.

Bonnin et al., 2002

Wasson (1935) CO2 continuous layerWAG-1981

Carbonates (wackestone–packstone) 5–10 mD

Peripheral waterinjection (1964)

35% OOIP (Pr.+Se.) 15% OOIP97 14.2 MM bbl(1983–2000) by infill99

Irregular pattern not suitablefor CO2, converted to 9-spot98

Tanner et al., 1992;Fox et al., 1994; Thaiet al., 2000

East VacuumGrayburg SanAndreas (1938)

260 MM stb(inject. area)

CO2–WAG–1985(WAG=2:1)

Carbonates (grainstoneand packstone) (11 mD)

1 cp 38 °API WF (1958)(80 acre — 9-spot)

40% OOIP (Pr.+Se.) 21–30 MM stb (8–11%OOIP) infill only: 1.5% OOIP

Harpole andHallenbeck, 1996

WF: Waterflooding, ROS: Residual Oil Saturation, OOIP: Original Oil In-Place, Pr.: Primary, Se.: Secondary, Te.: Tertiary, AC: Acid Gas, CH: Chase Gas.

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Table 4

A summary of tertiary chemical injection applications reported

Field(discovery year)

OOIP Injected fluid (year started) Formation type/permeability

μoil/°API Recovery history(starting year)

Primary and secondaryrecovery


Comments Ref.

Whittier (1966) Caustic (1966) 320–495 mD 40 cp 20 °API WF (1968) Secondary (WF)was weak

350,000–470,000stb (by 1973)

IFT reduced from20 to 0.002dyne/cm

Graue and Johnson,1974

Bradford Micellar slugs (petroleumsulfonates+cosurf.+polym.)field scale

Sandstone–siltstone(82 mD)

5 cp 45 °API Average 57% Oil saturation afterWF: 28–35%

Danielson et al.,1976

Loudon Microemulsion (corefloods only,no field trials)

Sandstone 6–7 cp 39 °API Pr.: 13 yrSe.: 38 yr

∼50% OOIP (Pr.+Se. in the field)

Rec. from cores:20–75% of ROS

Maerker and Gale,1992

Oerrel (1954) Polymer flood (1975) Sandstone 2.2 cp 38 °API 19.5% OOIP (Pr.+Se.) ∼20% OOIP Final predictedvalue 28%

Maitim and Volz,1981

Hankensbuettel(1958)

Polymer flood (1977) Sandstone 2.2 cp 38 °API 36% OOIP (Pr.+Se.) 12.5 % OOIP(predicted)

Maitim and Volz,1981

Marmul (1956) 390 MM m3 Polymer flood — pilot(5-spot) (1986)

High perm sand(up to 10D)

80 cp Model study: Pr.:20–30% (WF) Se.:25–30% (polym.)

59% OOIP inthe pilot area

Koning et al., 1988

Glenn Pool(1905)

11.5 MM bbl Surfactant injection (sulfonate+two alcohols) (1982)

Sandstone(150 mD)

4 cp 37 °API WF (1950) 70% (Pr.+Se.) 1.14 MM bbl (10%OOIP) (1979–1992)

Largest amountof surf. rec.

Bae, 1995

Big Muddy Low IFT (sodium petr. sulfonate)followed by 50% PV polymer(1973–1978) 5-spotpilot (one producer)

Sandstone(52 mD)

4 cp 35 °API WF (1953) In the pilot test area:68% OOIP

14,382 bbl (1032 preflush,13,350 Te.)

Saad et al., 1989

Pownall Ranch(1974)

Alkali-surfactant (1996) Sandstone(20 mD)

8 cp 26 API WF (1984) Oil rate increased from9000 to 12,500bbl/month

Injection rateincreased from12,000 to 17,500bbl/m after chemicals

Wyatt et al., 2002

Tanner —Minnelusa B

2.6 MM bbl Alkali+surfactant+polymer(2000–2002)

11 cp 21 °API WF Oil cut was 43%when ASP started

33,000 m3 (31% OOIP) Wyatt et al., 2002

Saertu Sand Alkali+surfactant+polymerpilot \ 4 injectors (1994)

Sandstone WF Oil cut increased from17% to 48% after WF

65,000 bblsincremental oil

Wyatt et al., 2002

Rapdan Pool(1955)

Polymer (1985) WF (1962) Estimated 15% OOIP Pilot: 41% OOIPcore: 39% OOIP

Wyatt et al., 2004

David Pool(1970)

Alkaline–polymer (1987) Sandstone(1.4D)

34 cp 23 °API WF (1978) Primary: 5.3% OOIPWF: 18.1 % OOIP

Pilot area: 52% OOIP(Pr. and Se.) 22%OOIP Te. polymer

Lab: cum oil was74% OOIP (24%from Te. polymer)

Wyatt et al., 2004

Daqing Alkali+surfactant+polymerfour inverted 5-spot (1994)

Sandstone(1.4D)

11.5 cp35 °API

WF WF: 21.3% OOIP Total prod. (Pr.+Se.+Te.)49% OOIP

Te.: 31% in thepilot area

Wyatt et al., 2004

Bell Creek 0.15 MM bbl Micellar-polymer (oil solublepet. sulfonate) (1979–1984)5-spot pattern

Sandstone(1D)

3 cp 32 °API 34% primary 15% WF 19% Schiltz et al., 1984

North Burbank 1.4 MM bbl Micellar-polymer (sulfonate)9, 5-spot pattern

Sandstone(50 mD)

3 cp 39 API WF (1954) 25% (primary) 6% (WF) 19% Schiltz et al., 1984

Robinson M-1 4.24 MM bbl Micellar-polymer (sulfonate)(1977) field scale

Sandstone(103 mD)

6 cp 36 API 60% 20% of remaining 40% Schiltz et al., 1984

Manvel Micellar-polymer (sulfonate)2 inj., 3 prod.

Sandstone(500 mD)

4 cp 29 °API 70% 44% of remaining30% oil

Schiltz et al., 1984

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Table 5A summary of tertiary thermal injection applications reported

Field(discoveryyear)

OOIP Injected fluid(year started)

Formationtype/permeability

μoil —°API

Recoveryhistory

Primary andsecondaryrecovery


Comments Ref.

Field H(1994)

Air Pr.+Se. (WF)produced 93% ofthe reserve

Additional rec.=200,000 stb (in 1 yr)400,000 stb after 3 yr

Core tests: 31%OOIP WF 6%OOIP air

Sakthikumaret al. 1995

LocoField

Hot waterpilot-inverted5-spot(1961–62)

600 cp WF Total recovery was∼4000 bbl

Water injectivityincreased 200–400%

Martin et al.,1968

MedicinePoleHills(1967)

Air injection(1985)

Deepcarbonate(1–30 mD)

39°API Pr. rec. est.: 15%OOIP

As of 1995 increm. oil:1 MM bbl (2.5% OOIP)

Kumar et al.,1995

WF: Waterflooding, ROS: Residual Oil Sat., OOIP: Original Oil In-Place, Pr.: Primary, Se.: Secondary, Te.: Tertiary.


recovery through performance monitoring, data acqui-sition and vertical conformance monitoring wasreported to be an effective management strategy formature fields (Stiles and Magruder, 1995).

Reservoir characterization attempts for developingmature fields are also applied commonly. Seismicstudies were performed to reduce the uncertainties onthe structure (Lantz and Ali, 1991; Pauzi et al., 2000)and locate the remaining oil (Lantz and Ali, 1991;Reymond et al., 1999; Pauzi et al., 2000) to developdifferent size mature fields. Reservoir simulation isgenerally used to assess the field potential for any devel-opment plan and reserves booking studies for theremaining oil (Blaskovich et al., 1985; Van de Leemputet al., 1997). This requires an accurate description of thereservoir. Campanella (2002) introduced a 60-year oldfield case with limited or low quality log and core data.Though the experience gained over decades is valuablein the development of mature fields, the data quality andlack of information could be problem, especially for oldfields. They suggested that the data integration shouldbe implemented as early as possible. Two recent studiesdiscussed the importance of advanced reservoir charac-terization techniques on the reactivation of two highlyheterogenous mature fields, namely the Womack Hill(Mancini et al., 2004) and the Budare (Hamilton et al.,2002).

The management strategies to follow in the devel-opment of mature assets are also dependent on the sizeof the company. Long-term plans and investments onmature fields are highly difficult to make for small sizecompanies. For comparison, two extreme mature fieldcases will be discussed here. The Yibal field, a fracturedchalky-carbonate with light oil, has been the mostprolific field in Oman over three decades. This field is a

good example of a big-mature-field operated by a bigcompany. At different stages of the production life,different development plans were tested and implemen-ted. The field went through primary depletion (1969–1972), water injection (1972–1981), aquifer injection(1981–1993), and intensive horizontal infill (1993–2001) (Mijnssen et al., 2003). A large scale simulationof waterflooding was performed to assess the secondaryrecovery performance in 1972 (several years after itsdiscovery) (Grant, 1981). In 1989, an appraisal strategyconsisting of the evaluation of the liquid-gas handlingfacilities, appraisal drilling, and western area develop-ment was developed. It was concluded that the initialconceptual reservoir model might not be representativefor the total structure (Bos, 1989). Eckford (1999)proposed an optimal plan for the surface facilities toprepare the field for the next 30 years. Recently, Al-Mugheiry et al. (2001) analyzed the field's 30 yearperformance to propose a new injection plan and locatethe mobile oil-in-place. They created a voidage mapafter an extensive pressure surveillance for the newinjectors. As seen the field went through many differentstages of development and currently reached its maturitywith significantly increasing WOR. Recently, Mijnssenet al. (2003) evaluated different development opportu-nities including a revision of large amount of datacollected so far for sector and full field modeling. Thefinal stage of the field development would be an EORapplication. Due to carbonaceous and fractured nature ofthe field, options were limited. Aqueous surfactantinjection potential was tested by Babadagli et al. (2002).They observed that the average waterflooding perfor-mance of the chalk samples with the original Yibal oilrecovery was 75% OOIP. Many different surfactanttypes and concentrations were tested on waterflooded


cores and the tertiary recovery potential was found to be0–7.5%. It has been observed that some parts of the fieldwere not touched mainly due to the heterogeneousstructure of the field. Therefore, the low IFT water-flooding performance was tested as a secondary re-covery technique rather than tertiary. It was observedthat the average recovery was around 69% OOIP, whichis lower than waterflooding performance. To evaluatethe recovery performance of the highly fractured parts ofthe field, the capillary imbibition performance was alsotested. Brine imbibition yielded 15% OOIP recovery.More than half of the experiments showed higher re-covery when the low IFT solution was used instead ofbrine. Obviously, starting the recovery with lower IFTsolution is preferable over the brine imbibition in thefractured zones provided that the proper surfactant typeand concentration were chosen. Development of thismature field through low IFT surfactant solution needsmore experimentation (SCAL, simulation and fieldpilot) and economic analysis. A similar developmentplan has been tested for mature North Sea reservoirs butno field application has been reported yet (Austad andMilter, 1997; Standnes and Austad, 2000; Standneset al., 2002; Austad and Standnes, 2003; Standnes andAustad, 2003).

Other example is a small field (the Sahmah field)containing very light (0.5 cp) oil owned by a smallcompany (Babadagli et al., 2001). The field has pro-duced for nearly 30 years from 20 vertical and 1 ho-rizontal well and steady decline has started despitestrong water influx through one side of the field. Onelayer (high permeability sandstone) was watered-out upto 70–75% OOIP oil recovery. Another layer (tightsandstone) with high OOIP did not produce almost anyamount of oil. Due to limited resources, the companywanted to limit capital investment avoiding new wells.Possibility of nitrogen injection was investigated. Thecore injection studies showed additional 6–8% OOIPrecovery over waterflooding. Note that this recoverywas due to immiscible displacement (and potentiallydouble displacement) only. The nitrogen injection intovirgin tight sand yielded up to 42% OOIP oil recovery.The performance was also tested by field scale nu-merical simulation and consistent results with theexperiments were obtained. Minimum injection pressurewas estimated 4500–5000 psi due to the depth of theformation (3200–3500 mss) and high reservoir pressureto overcome. The cost of the compressors for thispressure as well as the injected nitrogen turned out to bea project demanding some initial investment. Alterna-tively, air injection possibility, that could recover moreoil owing to the other possible recovery mechanisms at

lower cost, was searched. Although it is more economicthat nitrogen injection, possibility of risk at the pro-duction wells caused by unconsumed oxygen turned outto be a reason to rule out this option.

The above two cases can be considered two extremeexamples of mature field development. Although thetertiary (or secondary) recovery techniques are different,the amounts of additional oil recovery were similar. Inthe first case (Yibal field) the low IFT solution injectionseemed promising and economic application usingexisting water injection system and converting someproduction wells into injectors. This long-term invest-ment-intensive plan can be affordable for this sizecompany whereas in the latter case (the Sahmah field),the size of the company restricted the tertiary recoveryoption due to long pay out time and high investment inshort run.

The pay out time for EOR applications is generallylong and this may not be favorable especially for smallcompanies. Small companies' investments are typicallyfor short term and the focus is generally on the ac-celeration of the production rate that yields high NPV inthe beginning and shorter pay out time. On the contrary,big size companies can afford investments that targethigher ultimate recovery (or reserves) that may notnecessarily accelerate the production (or yield highNPV) in short term. It is prudent to estimate the righttime to start EOR applications to reach the highestpossible ultimate recovery at the end of the project.

Several well-known examples are worth mentioningin regards to the reservoir management practices ofmature fields. Extensive fracture network characteriza-tion has been a critical tool in the development of theYates field (Snell et al., 2000). The static reservoirmodels obtained through these characterization studieswere used in the performance estimations of differentEOR techniques (Winterfeld, 1996; Dershowitz et al.,2002). Monitoring the process using seismic andlogging techniques was also observed as a useful toolin the development this field (Snell and Close, 1999).Characterization of the properties of complex fracturesystems such as density, orientation, connectivity, andaperture has been an essential part of the developmentplans for big mature fields such as the Spraberry (Bakeret al., 2001), offshore Abu Dhabi (Gauthier et al.,2002), and the giant Ghawar field (Phelps and Strauss,2002).

A few reservoir management practices that wereapplied to nearly abandoned small fields were alsoreported. Horizontal wells and waterflooding optimiza-tion were proposed for the Espoir Field in Ghana andpotential increase in the recovery was observed with 5


horizontal and 3 injectors using simulation (Lencioniet al., 1996). Optimized secondary recovery was foundto be applicable to revive a nearly abandoned field inIllinois (Aman, 1999).

Recently, Wilkinson et al. (2004) provided an anal-ysis of the experience gained from mature carbonatefields that yielded additional 8 to 20% OOIP recoveryusing systematic and integrated reservoir managementapproaches. The fields evaluated were the Jay field, theSlat Creek field, and the Means field. Different EORtechniques such as CO2, acid gas water, miscible–immiscible gas and foam-WAG assisted CO2 injectionhave been applied in those fields. The key parameterswere observed as reservoir description, fluid composi-tion, relative permeability, reservoir pressure, welltrajectories and completions, and process selection.

Excessive water production is one of themost commonproblems to be dealt with in mature fields. The remedies(water conformance) have generally to do with well en-gineering which is beyond the scope of this paper thatreviews basically reservoir scale management practices.

It should finally be noted that one of the most criticalaspects of reservoir management is the collection andintegration of good quality data. Data collection iscommonly ignored as the field ages and its cost isobvious. Although the production-rate-data will beavailable throughout the history of the field, most ofthe production wells that are opened at late stages are notcored and logged or continuous monitoring of pressurehistory is ignored to due to excessive cost. Often times,water and especially gas productions are not carefullymonitored if they do not have any commercial value.This causes lack of critical information in materialbalance and reservoir simulation practices. Therefore,continuous data gathering and its integration startingfrom the drilling of a well are critical. Determination ofwhat type of data to be monitored, collected, andevaluated during the course of production should bedone at very early stages and this should be a continuousprocess to create a good quality data bank at the laterstages of the production. An alternative to this is toconduct data collection campaigns after the field reachesits maturity as suggested (Mijnssen et al., 2003) andimplemented (Al-Mugheiry et al., 2001) by recentstudies. As the field gets matured, 4-D seismic andsaturation logs as well as updating reservoir modelsusing the most recent data for locating new wells orimplementation of enhanced oil recovery techniquescould be necessary. However, it is more cost efficient tocollect other types of data such as well information andreservoir pressure in continuous manner during theproduction before the field reaches its maturity.

8. Well placement, infill drilling, horizontal wellsand optimizing waterflooding

As a field gets matured, it is necessary to drill newwells to recover the remaining oil reserves that aretrapped due to heterogeneity or in the unswept zones.Shirzadi and Lawal (1993) proposed a multidisciplinaryapproach for the Prudhoe Bay field that increased therate in short term and ultimate recovery in long term.Success stories of improved oil recovery through infilldrilling in mature fields were presented for differentfields (Javed, 1995; Fah et al., 1997; Nosseir et al.,1999; Ghosh et al., 2004). It is essential to determine theoptimal well placement for mature fields and this re-quires accurate mapping of remaining oil distributionand description of heterogeneity (Vincent et al., 1999).

Holm (1980) compared infill drilling, waterfloodingand EOR techniques as reservoir management strategiesfor mature fields. He stated that the infill drilling is lessexpensive and accelerate the production of oil. Infilldrilling is the only way to recover oil trapped due toheterogeneity. In that sense, it increases reserves. EORmay not require additional well drilling but pay out timeis generally too long that is not favorable for especiallysmall companies. Although it is the most expensivechoice, a combination of infill drilling and EOR wouldyield the most beneficial development scheme. Heconcluded that the earliest increase in the reserves isobtained in 2 to 3 years when the EOR and infill optionsare applied together. The most suitable method is che-mical injection for this type of approach.

Other practices that have been applied in mature fielddevelopment include the development plans throughoptimized waterflooding (Stiles, 1976; Woodling et al.,1993; Vincent et al., 2002; Hendih et al., 2002) andhorizontal drilling (Taber and Seright, 1992; Al-Shidhani et al., 1996; Palasthy et al., 2000; Edwardset al., 2002). The Wilmingon field waterflooding opti-mization study was performed by mapping the produc-tion gross and oil, and water cut bubble maps, injectionstreamline maps and pattern performance graphs after55 years of production (Woodling et al., 1993). Vincentet al. (2002) proposed a development policy for a maturewaterflood project by optimization of well locations,management of subsurface uncertainties and a decisionscheme for whether a well remains a producer orinjector. After an extensive simulation and optimizationstudy, they showed that the technically and economi-cally optimal solution was to convert 6 of 11 wells toinjector. Hendih et al. (2002) evaluated four options (donothing, infills at low cost and low rate, pattern water-flood re-alignment, and shut in some of the injectors) for


the mature Minas field that produced 13% OOIP byprimary recovery and 29% OOIP by peripheral waterinjection, and 1.4–2.7% OOIP by pattern waterflooding.They found that the realignment of 7 infill wells wouldbe an economic application even though those wellsrobbed oil from other producers. Stiles (1976) proposedan optimal mature waterflood application for the Full-erton Cleakfork Unit by converting 82 wells to injectors,phasing out 35 injectors, drilling 61 infill producers, andconverting 42 more wells to injectors to implement 1 to 1line drive in the west part of the field. The project wasinitiated and it was observed that 36% of the totalproduction was from the infill wells.

The Yibal field in Oman is an excellent example ofmature field development using horizontal wells. After25 years of production, a high density-horizontal infillcampaign was started. In 1996, 100 horizontal wellswere drilled from which 60% of total oil production wasobtained. It was observed that they yielded higher pro-duction, improved recovery, higher optimization gains,reduced operating cost, and enhanced safety (Al-Shidhaniet al., 1996; Mijnssen et al., 2003). Within 5 years, therecovery factor jumped from30% to 40%but thewater-oilincreased nine fold (Mijnssen et al., 2003).

Successful applications of the use of horizontal wellsin EOR applications were also reported. A good ex-ample is the mature miscible flood in the Swan Hillsfield. After 10 years of waterflooding (1963–1973),hydrocarbon miscible injection was started in this field(Griffith and Cyca, 1981). Then, it was converted to achase gas injection in 1989 and the solvent injection wasreinitiated in 1994 in a single pattern using a horizontalinjector and reduced well spacing (Edwards et al.,2002). Four patterns were developed in 2002 expecting10% OOIP incremental recovery from the first twopatterns. Based on the height of the reservoir, optimalinjection rates and well spacing were determined toprevent any gravity override. It was reported thatconverting the hydrocarbon miscible flood injectors tohorizontal producers did not perform well. A region ofhigh gas saturation around the converted well led toearly breakthrough because of high gas relativepermeability. The success of the horizontal patternsresulted from the placement of the horizontal wellbore atthe bottom of the pay and tighter well spacing that bothmaximized the sweep efficiency. Another successfulapplication of horizontal wells was reported by Palasthyet al. (2000). The Algyo field in Hungary was developedby vertical oil producers between 1975 and 1985 fol-lowed by a gas lift operation. Pressure maintenance bywater injection was started in 1985. In 1993, a projectwas initiated to recover by-passed oil by horizontal

wells. In 1999, the recovery factor reached 22% andcontribution from the horizontal wells to the recoverywas 26%. Prospect was 41% OOIP ultimate recovery ofwhich 12% is due to horizontal well.

Taber and Seright (1992) evaluated the performancesof tertiary recovery techniques (gas, chemical, andthermal injections) when horizontal wells are used. Theyobserved that the sweep increased and low injectionpressure was required for all these techniques but fasterrate was observed for chemical (polymer and alkaline-micellar) and CO2 injection only.

The scope of this review paper was limited toreservoir engineering applications and enhanced oilrecovery in mature field development. Well and surfacefacilities related issues comprise the other aspects ofmature field development. One of the most commonwell related problems is increasing water production.Water shut off techniques using gelled polymers wereproposed and tested for mature fields (Willhite et al.,2000; Fowler, 2004). Other possible well engineeringapplications in mature field development include scalecontrol (Jordan et al., 2006) and using alternative arti-ficial lift systems (Eson, 1997). Two other studies re-garding the mature field development proposed low costproduction (Pasni and Wibowo, 2000) and workover/completion (Fabel et al., 1999) operations.

9. Concluding remarks

In this paper, reservoir engineering practices todevelop mature fields were covered with the emphasison tertiary oil recovery and several other reservoir man-agement strategies. It is clear that almost all of the giantfields in the world reached their maturity still have aconsiderable amount of oil left behind to be recovered.Increasing oil prices made small size fields that wereabandoned due to uneconomic operational conditions bybig companies attractive to small companies. Because ofthese reasons, mature field development is increasinglybecoming an attractive but challenging topic.

The very first challenge in the mature field devel-opment is to locate the remaining oil, which occurs dueto inefficient displacement (residual oil in the pores ofthe swept zones) or poor sweep (by passed oil). Next,the right technique to develop the field should bechosen. All these require exhausting optimizationstudies and long term planning. Often times this turnsout to be a difficult exercise due to uncertainty in the oilprices and other instabilities.

Mature field development plans, especially thetertiary recovery attempts, require a clear identificationof the ultimate goal. The amount of oil recovered by


tertiary methods is normally less than the secondary (orprimary) recovery techniques while the cost is generallyhigher. Small size companies typically target the ac-celeration of the recovery whereas big size companiesmay afford slower recovery at the beginning targetinghigher ultimate recovery. Therefore, the tertiary recov-ery techniques that require longer pay out time andinvestment, due to additional wells drilled and cost ofthe injectant, could be more attractive for big fieldsowned by big size companies. Another issue to beconsidered is the microscopic efficiency of tertiaryrecovery techniques that might remarkably be affectedby the amount of remaining water from the secondarytechniques. Therefore, it is important to decide on whenthe right time is to switch to tertiary method to reach thehighest possible value of ultimate recovery at the end ofthe project.

NomenclatureA Reservoir areaBo Formation volume factor of oilBg Formation volume factor of gasBt Two-phase formation volume factorBoWF Formation volume factor of oil (after

waterflooding)BW Formation volume factor of water(Ci)oil Concentration of tracer i in the oil phase (mol/

volume)(Ci)water Concentration of tracer i in the water phase

(mol/volume)co Reservoir oil compressibilityct Reservoir rock compressibilitycw Reservoir water compressibilityCo Conductivity of 100% brine saturated sampleCw Conductivity of brine.E Bleeding factor (1.1).F Formation resistivity factorGi Cumulative gas injectedh Formation thicknessIFflow Free Flow Indexk Permeabilitym Ratio of initial gas cap size to initial oil zone

sizeM Mobility ratioM Oil average molecular weightn Saturation exponent (1.4–2.8)Nfoi Initial oil in placeNp Oil producedPc Critical pressureq Production rateQv Meq of exchange cations per cc of pore spacer Radius

Ro Resistivity of 100% brine saturated sampleRp Cumulative produced gas–oil ratio (scf/stb)Rs Solution gas oil ratio (scf/stb)Rt True resistivity (measured by log)Rw Resistivity of brinePSoð Þres Average waterflood residual oil in the reservoir

(flooded region)PSoð Þcores Average waterflood residual oil from coresSo Oil saturationSor Residual oil saturationSorm Miscible and near-miscible residual oil saturationSow Spreading coefficientSw Water saturationT TemperatureV Permeability variationVw Water velocityVo Oil velocityWe Cumulative water influx, rbWi Cumulative water injected, stbWp Cumulative water produced, stbΔP Pressure drop, psiϕ Porosityμ Viscosityρ Reduced density (ρ /ρc)ρc Critical densityδ Solubility parameter, m0.5/t L0.5

σog Interfacial tension between oil and gasσow Interfacial tension between oil and waterσwg Interfacial tension between water and gas

Acknowledgment

This paper is the revised version of SPE 93884presented at the 2005 SPE Europec Biennial Conferenceheld in Madrid, Spain, 13–16 June 2005.

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