Bianca Anne Bealessio, Natalia A.Blˊanquez Alonso, Nicholas John Mendes,Anna Vladimirovna Sande, Berna Hascakir

Petroleum Engineering Department, Texas A&M University, United States

ABSTRACT Application of enhanced oil recovery methods in Kazakhstan has been ongoing for decades alongside the continued discovery of new oil and gas fields in the Pre-Caspian Basin.The objective of this review is to provide an overview of the hydrocarbon reserves and production,and the status of the petroleum industry in Kazakhstan, with a focus on the EOR methods and projects being applied to recover those reserves.A summary of the specific EOR methods in use was prepared, and existing enhanced recovery projects in Kazakhstan were reviewed and their successes and challenges were investigated.The performance of these projects in the context of EOR performance indicators such as capillary number and mobility ratio,as well as operational and environmental issues, were examined.Recommendations for current and potential applications of EOR in Kazakhstan were also discussed.The widespread application of thermal EOR methods, in use for decades in Kazakhstan’s older fields, was found to be successful, with very favorable impacts on mobility ratio from the addition of thermal energy to the reservoirs.Miscible EOR methods in Kazakhstan have had more limited success,with some significant challenges due to high concentration of hydrogen sulfide in the injected gas.Polymer injection started in the late 1960s,achieving good results.A recent polymer injection pilot project has shown some promise,with a favorable impact on mobility ratio and oil production,although the project has not yet been expanded beyond two polymer injectors.These results indicate the huge potential of existing and future EOR projects.This review is the first compilation of Kazakhstan’s existing oil and gas reserves,production,and EOR project performance,and should be seen as a guide to the existing applications of EOR methods in Kazakhstan.

Keywords:Kazakhstan Thermal EOR Sour gas injection Polymer flooding

1.Introduction

Kazakhstan is an oil and gas producing country located in Central Asia and Eastern Europe.The presence of hydrocarbons in the area of present-day Kazakhstan was first established in the mid-1800s [1].In 1899, a 40 m deep well drilled by the Emba-Caspian Group in the Karachungul field produced the first oil on an exploration concession block in Kazakhstan [2].This well produced 12-25 metric tons per day of oil.However,it was considered to be subcommercial due to the remoteness of the field [1].

Subcommercial discoveries continued in the oil provinces of Kazakhstan over the next decade.Production from the first commercial oil well in Kazakhstan began in 1911 from a 225 m deep well in the Dossor oilfield.This well produced over 270 tons of oil in a 30-h period.Over the decade of the 1910s, more than 350 wells were drilled in search of oil and production boomed.The first national oil company(NOC)of Kazakhstan was founded in 1912 to explore for oil.This company and others continued to discover and develop significant accumulations of hydrocarbons in Kazakhstan[2].

Since then,many fields have been discovered in Kazakhstan.The Pre-Caspian Basin, where the majority of fields are located, encompasses the western part of the country and the Caspian Sea.

Fig.1.Map of Kazakhstan with hydrocarbon fields of interest (After Google Maps 2019).

Currently, Kazakhstan has significant accumulations of both oil and gas, including nearly 300 discovered oil fields and over 60 discovered gas condensate fields[3].According to the BP Statistical Review of World Energy [4], Kazakhstan has 30 billion barrels of proved oil reserves and 1.1 trillion cubic meters of proved gas reserves,the 11th greatest oil reserves volume and the 25th greatest gas reserves volume in the world.Commercial production in 2017 was 1.84 million barrels per day of oil and 74.2 million cubic meters per day of gas.Approximately 80% of the oil and 60% of the gas produced is exported, mainly to or through China and Russia,through pipelines owned wholly or in part by KazTransOil, the national oil transportation company of Kazakhstan, or Russian pipeline operator Transneft [3,4].

Oil and gas exploration and production in Kazakhstan is controlled partly by the government.The NOC of Kazakhstan is KazMunayGas (KMG), which often partners with international oil companies through production sharing agreements, including projects at the Kashagan, Tengiz, Karachaganak, and Karazhanbas fields.KMG wholly owns a few subsidiaries including UzenMunayGaz, which operates the Uzen field [3].The major oil and gas producing fields discussed in this manuscript include Uzen and Kenkiyak, discovered in the 1960s, Karachaganak, Karazhanbas,and Kalamkas,discovered in the 1970s,Tengiz,discovered in 1980,and Kashagan,discovered in 2000[2].The locations of these fields are given in Fig.1.All but Kenkiyak are in the Pre-Caspian basin[5].

Beginning in the 1960s,when Kazakhstan was part of the Soviet Union,Enhanced Oil Recovery(EOR)pilots began in Kazakhstan[1].Currently, several EOR methods are still being applied in Kazakhstan which include both thermal and nonthermal methods.The focus of discussion in this manuscript will be on hot water injection, cyclic steam injection, steam flooding, in-situ combustion, polymer flooding, and miscible flooding with sour gas in several fields.

2.Factors affecting enhanced oil recovery(EOR)performance

The main objective of any EOR project is to improve the oil displacement efficiency.Hence,in this manuscript,performance of EOR methods applied in Kazakhstan will be evaluated in terms of oil displacement efficiency.The factors affecting oil displacement efficiency will be discussed both in microscopic scale (pore scale)and macroscopic scale (volumetric scale).Thus, it is useful to start by summarizing important performance indicators for enhanced oil recovery processes.

The displacement efficiency is given by the following equation Displacement Efficiency,

where EVis the volumetric sweep efficiency and EDis the microscopic sweep efficiency.

The Capillary Number and the Mobility Ratio are two important dimensionless numbers that provide information on the effectiveness of microscopic and macroscopic displacement efficiencies,respectively[6].

Where ν is the interstitial velocity, μDis the viscosity of the displacing fluid, σoDis the interfacial tension between the displaced and displacing fluids, and θ is the contact angle [7].

Where krDand kroare the relative permeabilities of injected fluid and reservoir oil respectively and μDand μoare the viscosity of injected fluid and reservoir oil respectively.

Another factor to consider is the viscous to gravity ratio

Where u is the velocity of the injected fluid,μois the oil viscosity,k is the permeability, g is the gravity constant,Δρ is the density difference between the injected fluid and reservoir oil, L is the horizontal distance in the reservoir, and h is the height [8].

3.Enhanced oil recovery methods currently applied in Kazakhstan

In the following sections, thermal EOR methods, polymer flooding, and miscible flooding with sour gas injection will be discussed for Kazakhstan oil fields.First, each EOR process will be briefly discussed and then the success of each EOR project will be given in detail below.A summary of the fields, EOR methods,application, and status is shown in Table 1.

Table 1 Summary of EOR fields of Kazakhstan discussed herein.

Thermal EOR Overview: Among all thermal enhanced oil recovery methods, hot water or steam injection processes are the most preferable due to their simplicity, which results in mostly predictable outcomes [9].The main oil displacement mechanisms in these EOR processes are reduction of interfacial tension,change in wettability, viscosity reduction, and thermal expansion.As the density of the oil increases, the significance of viscosity reduction and wettability alteration increases and thermal expansion decreases [10].However, it should be noted that while hot water or steam injection methods have several advantages over many thermal EOR methods,they cannot be applied in certain reservoirs in which for instance steam cannot be used due to significant reservoir depths [11].For those cases, in-situ combustion (ISC)provides an alternative.The produced oil is upgraded in-situ causing a lower oil viscosity, higher API gravity, lower sulfur content, and lower heavy metal content [12-16].

Polymer Flooding Overview: The objective of polymer flooding is to increase the volumetric sweep efficiency (macroscopic-scale)by adding polymer to the injected fluid and increasing the injected fluid’s viscosity (μD), which reduces the mobility ratio.Anothereffect is the reduction of viscous fingering and the decrease in relative permeability, particularly in layers of high permeability,obtaining a more equal conductivity through the reservoir [17].Consequently, high-permeability zones become more resistant to the injected fluid and therefore, it is diverted to layers of lower permeability, allowing a higher sweep efficiency.

Miscible Sour Gas Flooding Overview: Sour gas is defined as a gas which contains significant amounts of H2S,generally more than 5.7 mg H2S/m3of natural gas(equivalent to approximately 4 ppm)[18,19].At certain temperatures and pressures this gas is miscible with oil in the reservoir.Due to the miscibility of sour gas with the oil in place, oil displacement is achieved through reduced interfacial tension,oil swelling,an increase in relative permeability to oil,and significant reduction in oil viscosity [6,19,20].

Compared to other gas injection methods(sweet gas or CO2injection),sour gas injection causes greater viscosity(μD)and density(ρD)reduction,resulting in an increase in the capillary number and decrease in mobility ratio by reducing gravity override.This is because of the lower Minimum Miscibility Pressure(MMP)of sour gas.Consequently, reduction in MMP results in improved sweep efficiency with respect to other miscible gas methods[20,21].

Additional advantages of this method include reservoir pressure maintenance, reduction of storage requirement of sour gas, and cost reduction compared to sulfur removal.However, potential risks are the highly corrosive and toxic features of H2S, making its handling critical.

3.1.Thermal EOR methods

A variety of thermal EOR methods are utilized in Kazakhstan.This section will discuss mainly three thermal EOR processes applied in Uzen,Kenkiyak,and Karazhanbas fields.The reservoir oil and rock properties of these fields are listed in Table 2.Kenkiyak and Karazhanbas fields are classified as heavy oils[22],while Uzen field has high paraffin(wax)content.To increase the mobility of the heavy oils in Kenkiyak and Karazhanbas fields and to decrease the paraffin deposition risk in Uzen field, thermal EOR methods are currently applied.In Uzen field, hot water flooding; in Kenkiyak field,cyclic steam;and in Karazhanbas field,steam flooding and insitu combustion(ISC) are applied.

Table 2 The reservoir rock and fluid properties of Uzen,Kenkiyak,and Karazhanbas oil fields in Kazakhstan [23-28].

A significant amount of understanding and value can be derived from studying these thermal projects because of the unique nature of their size, length of implementation, and the results that were obtained.The details of each EOR method applied in each field will be given in the next three subsections.

3.1.1.Uzen Oil Field

The Uzen field,discovered in 1961,is estimated to have over 8.4 billion barrels of original oil in place.By the late 1960s, saltwater transported from the Caspian Sea was injected to maintain reservoir pressure[26].The field is currently producing with a water cut above 70%[24].

In 1967, the recommendation by Soviet Union researchers was to initiate a hot saltwater flood,but the Kazakh Institute for Design and Planning of Establishments of the Petroleum Industry and Soviet Union field managers moved forward with cold saltwater flooding to get production online as quickly as possible.The researchers anticipated that the high paraffin content would become a major obstacle during cold saltwater flooding because testing showed that paraffin crystallization (i.e.wax) developed at temperatures 5-10°C below initial reservoir temperatures [29].The 3°C Caspian Sea water that was injected into the 54°C-69°C reservoir resulted in paraffin deposition around the injectors [30].Studies confirmed that the paraffin deposition caused a significant pseudo skin to form around the injectors, which clogged the pore spaces, reduced injectivity, decreased the capillary number, and negatively impacted microscopic displacement [31].In addition to the injection challenges,the interaction between the saltwater and heavy crude oil components formed corrosive and non-corrosive compounds that damaged producers and surface facilities and caused deposition in the equipment [29,32-34].These reservoir and surface challenges associated with cold saltwater flooding limited the field to an expected ultimate recovery factor of 23%[24].

Due to the obstacles posed by the high paraffin content of the crude oil, the world’s largest hot saltwater injection project was eventually implemented in the early 1980s [35].At temperatures approaching 90°C, hot saltwater flooding alleviated some of the issues caused by cold saltwater flooding [36].Hot saltwater injectors could maintain their injection rates and therefore,maintain a favorable capillary number, which enhanced pore-scale displacement; however, the damage caused by cold saltwater flooding continued to plague production in the following decades[26].Even with the inherited reservoir damage, hot saltwater flooding was a more effective method for recovering oil, and is expected to achieve an ultimate recovery factor of 38% [24].

Ultimately,the Uzen Oil Field has had a long and difficult history.In retrospect,using heated fresh water would have avoided most of the negative side effects that limited performance and the true potential of this supergiant could have been realized.

3.1.2.Kenkiyak oilfield

The Kenkiyak field was produced through depletion beginning in 1967, reaching water cuts up to 80% [37].However, the field contains heavy oil at shallow depths, making it an ideal candidate for thermal recovery via steam injection[28].Wet(saturated)cyclic steam injection began in 1975 with great success, and a superheated cyclic steam injection pilot began in 2006.The estimated primary recovery was 21.6%and oil rate increased by 61.9%after the application of superheated cyclic steam injection [37].

When vapor steam is injected into a cold,heavy oil reservoir,its high heat capacity is efficiently transferred, which lowers oil viscosity and results in reduced interfacial tension and increased volumetric flow velocity [10,38].The Kenkiyak field contains 5 million barrels of this cold,heavy oil,and superheated cyclic steam injection has been both modeled and pilot tested as an EOR technique [28].Superheated steam has a temperature that is well beyond the boiling point temperature of water and is also referred to as dry steam (100% vapor).If designed correctly, superheated steam can lose heat while traveling through surface infrastructure and down the wellbore without condensing[39].While this is the most efficient way to reduce the oil viscosity and improve sweep efficiency, it comes at a financial cost.It takes more fuel gas, and therefore,higher operating costs,to generate superheated steam as compared to saturated steam.

3.1.3.Karazhanbas Oil Field

The Karazhanbas field also contains heavy oil with viscosities ranging from 375 to 550 cP[23].It has been extensively developed due to a large resource target.Both steam flooding and in-situ combustion (ISC) techniques have been utilized at Karazhanbas over the last 30-40 years to recover oil from its estimated 400 million barrel of oil reservoir [36].Fig.2 gives shows a map of Karazhanbas with thermal EOR application locations.

Steam flooding follows the same principles described in the Kenkiyak oil field; however, continuous steam injection is used instead of cyclic steam injection in Karazhanbas field.Because with continuous steam injection the heat delivery to the reservoir is more stable, steam flooding has yielded incremental recoveries as high as 40% over a 20-year period [23,40].The location of these steam projects are the areas outside the in-situ combustion (ISC)polygons shown in Fig.2.These areas do not appear to have a consistent spacing or pattern orientation across the field;however,with a detailed review of recoveries by area and by zone and a wellplanned redevelopment,recompletion,or down-spacing campaign,additional reserves may be accessible [41].

Two types of in-situ combustion (dry and wet) processes were applied in Karazhanbas Field.In Zone 1 shown in Fig.2, dry combustion and in Zone 2 and Zone 3 shown in Fig.2,wet combustion were implemented.With the implementation of wet combustion,32%-40%incremental recovery was achieved over a 13-year period with a 40%-60% water cut, whereas dry ISC was less effective,achieving a 20% incremental recovery over a similar timeframe with a water cut between 24%and 46% [23].

3.2.Polymer flooding

Another EOR process widely used in Kazakhstan is polymer flooding.This technology was first tested in the former Soviet Union in late 1960s and became popular among different fields of this territory, with relatively high efficiencies.This method was improved continuously with the introduction of new types of polymers [43].

3.2.1.Kalamkas oilfield

In this section Kalamkas field will be discussed.Kalamkas is located onshore close to Karazhanbas field (Fig.1) and Table 3 shows the notable reservoir parameters.Currently, the field is operated by MangistauMunaiGas (MMG), which is a 50/50 joint venture between China National Petroleum Corporation (CNPC)and KMG [44].

Table 3 Reservoir rock and fluid properties of Kalamkas Field [17,46,48].

The field was discovered in 1976 [45] and exploration and development began in 1979[46].Oil production from both natural reservoir energy and polymer flooding increased by 1984 from 200 tons per day to 11,000 tons per day.From 1985 until 1994 production stabilized at about 15,250 tons per day by means of water flooding, polymer flooding, and favorable reservoir energy.Between 1995 and 1998, during the decline stage, water injection operations were performed to some extent.However,the overall oil production decreased because the arrangement of the wells was not optimal, and the quantity of new wells drilled dropped.Since that time, several adjustments have been made with the objective of maintaining oil production and water cut,including optimization of horizontal well design,re-perforation,and fracturing[47].In the last few years, Kalamkas has become a mature field, with high water cut and low recovery factor[17].

The main challenge in this reservoir is the high level of permeability heterogeneity, which leads to risks of early breakthrough and therefore,low sweep efficiency of lower permeability layers due to high mobility ratios and small viscous to gravity ratios.There is also a high water salinity, which can affect polymer stability.

In 2014 a new pilot project for polymer injection started,which consists of two injection wells and 23 production wells,with initial conditions of 90%water cut and 26.6%recovery factor.The selected polymer for this project was partially hydrolyzed polyacrylamide(HPAM), which resists water with high mineral content and high salinity.A polymer concentration of 2,000 ppm provided an average viscosity of 24 cP of displacing fluid, reaching almost 40 times the original viscosity value.This has a direct impact,reducing mobility ratio and therefore, increasing the sweep efficiency, and minimizing viscous fingering.

The results are that vertical sweep efficiency in injection wellsdoubled and tripled (increased from 26% to 50% in one well and from 28%to 77%in another well),and oil production increased by of 88,040 tons.It should be noted that due to the liquid production increase, a production optimization process had to take place for downhole equipment,which accounted for an additional 5,218 tons of produced oil.A total of 1,218 tons of polymer were used, giving an overall increment in oil production of 76.6 tons of oil per ton of polymer used.While oil production nearly doubled, around 10%decrease in water cut was observed [17].

3.3.Sour gas injection

Sour gas injection is currently in use in Kazakhstan,particularly in the Kashagan and Tengiz fields.The next two sections will summarize the sour gas injection progress in these two fields and Table 4 summarizes their reservoir rock and fluid properties.

3.3.1.Kashagan oilfield

The North Caspian Project is a very important oil and gas development located offshore in the Caspian Sea and includes the development of five fields in the area(see Fig.3,left).One of those fields is Kashagan (Fig.3), which is considered the largest hydrocarbon discovery of the world in the past three decades, with recoverable oil volumes between 1 and 2 billion tons [50,57,58].Kashagan reservoir properties are given in Table 4.A contract was signed in 1997 with North Caspian Operating Company (NCOC),which is a consortium formed by KMG, Eni, Shell, ExxonMobil,Total, CNPC and Inpex [57].The discovery of the field was announced in 2000 and in 2013 the first oil was produced,but after a few weeks, pipelines transporting gas from offshore to onshore facilities started to leak due to the corrosive features of the sour gas and production was halted [59].

The reservoir comprises an isolated carbonate buildup from the Late Devonian to Middle Carboniferous periods with various zones.As seen in Fig.3,in the middle,a flat,highly stratified region called the“Platform Interior”can be distinguished,which has an elevated structure surrounding it (the “Rim”).The zone between the Platform Interior and the Rim is called the Transition Zone.The Rim presents a low-permeability matrix in which most of the fluids are stored, combined with regions of high porosity and permeability due to the presence of natural fractures [19,50,61].As a consequence of the Rim heterogeneity with high-permeability layers,there is a risk of early gas breakthrough and therefore, the project development is first taking place in the Platform Interior and Transition Zone [49].

The Kashagan field development is divided into two phases:Phase 1 is the“Experimental Program”(EP)which has an extension until 2023, whereas Phase 2 comprises the Full Field Development.The main activities for the EP Phase are the reservoir quality evaluation,production and injection data acquisition and evaluation,well performance data acquisition and evaluation,and areal and vertical sweep efficiency assessment [49,62].The initial experimental studies showed that first contact miscibility (FCM) is achieved between reservoir oil and injected sour gas which led to promises of a field scale trial of sour gas injection[63].However,the high content of H2S in the produced gas and high injection pressure requirement resulted in challenges in sour gas injection projects[20,63].

Moreover,the experimental studies showed that the asphaltene precipitation risk in the field is also reduced in the presence of H2S.Even though there is a low potential of asphaltene precipitation in Kashagan field (only a maximum of 5% pore volume), asphaltene build-up can be a problem and affect the EOR process performance negatively.Asphaltenes are known to be the most polar and the highest-molecular-weight component of crude oils and are not soluble in normal alkanes.Precipitation of asphaltenes is controlled by phase behavior, hence sudden changes in reservoir pressure,temperature, and reservoir fluid composition (PVT) may trigger asphaltene precipitation [64,65].As a consequence, asphaltene precipitation is commonly observed near wellbore, where PVT behavior of reservoir fluids can change drastically [63,66-69].For Kashagan field,a recent study suggests that asphaltene risk in this field depends on the well location and temperature (which varies from reservoir to surface),but it is reduced in the presence of H2S in the injection gas [61,70].However, in CO2injection processes, the possibility of asphaltene precipitation is more likely,since CO2is an asphaltene insoluble solvent [71].

The positive experimental results of sour gas injection led to restarting oil production in 2016 and it has been increasing since then (Table 5).While the oil production is limited by the sour gas processing capacity onshore, with the sour gas reinjection process oil recovery is increased and sulfur production minimized [57].

Additionally, for 2019, the average oil production has been 340,000 barrels per day(approximately 43 thousand tons day and 15.7 million tons of oil per year considering the density of Kashagan oil an average value of 804.6 kg/m3)[62,72,73].This shows that oil production has been continuing with the trend.Also, in Table 5, it can be seen that in 2018,reinjected gas accounted for almost 30%of the produced gas.

Table 4 The reservoir rock and fluid properties of Kashagan and Tengiz oil fields in Kazakhstan [49-56].

Table 5 Oil, gas, and sulfur production in Kashagan Field [57].

Fig.3.North Caspian Project and Kashagan Field locations (left) and Kashagan Field Depositional Environments (right) [51,60].

Still, there are a lot of challenges including the management requirement of huge sour gas volumes, high reservoir pressure,limited facilities for transportation of oil and gas, and complex geological conditions [74].One potential risk is the caprock integrity during injection,which could lead to early gas breakthrough.In this case, it is important to understand in-situ stress distribution and to determine maximum bottom-hole injection pressure and optimal well trajectories.Also, monitoring of fractures’ initiation and development should be a continuous effort [63].

Another challenge is the special environmental conditions in the field.Firstly,average temperatures vary between-38°C and 45°C,and the North Caspian Sea is frozen for several months in winter,which requires vessels and facilities that can handle ice and cold temperatures.Additionally,the North Caspian Sea level varies up to 0.5 m depending on the season and the coastline could be moved by effect of wind up to 30 km inland or up to 10 km offshore [58].Finally,the Caspian Sea region has a sensitive ecology,since it is one of the main habitats of the sturgeon and the endangered Caspian seal.It is also habitat of aquatic and subaquatic birds,as part of their migration route [74,75].

3.3.2.Tengiz oilfield

Tengiz and Korolev (location shown in Figs.1 and 3) are operated by TengizChevroil (TCO) under concession agreement for 40 years.Tengiz reservoir properties are given in Table 4.

Table 6 Properties of Karachaganak reservoir [88].

EOR with miscible gas injection was first tested in Tengiz with sweet gas injection in January 2007.The gas injection strategy for this project is given in Fig.4(a).The size of the circles indicates the relative production and injection volumes for each well.The initial injection started with 4 wells,shown by the larger red circles in Fig.4(a).After six months a first attempt at sour gas injection was performed;however, due to technical issues, continuous sour gas injection was delayed until January 2008.In August 2008, gas breakthrough(defined as gas-oil-ratio greater than 10)occurred in two close-spaced wells 100 m from an injection well, which raised concerns.The maximum injection rate was pumped into well T-5646 in the Serpukhovian and Visean intervals.The Bashkirian formation was the main source of production and thus the most depleted interval,therefore,most of the reinjected sour gas was pumped into it.A sixth of total production, 6 million cubic meters per day, over 4.3 billion cubic meters,was reinjected back into the reservoir as of July 2010[53].

The government limitations on flared gas, in effect from 2010,and limited market for the elemental sulfur gives additional incentive to reinject sour gas into the formation.The remoteness of Kazakhstan makes it difficult to export granulated and flaked sulfur to potential markets, although some is sold to China, Eastern Europe, and Africa.The majority of it (around 2,000 to 3,000 tons per day) is stored on the ground as shown in Fig.4(b) [76].

The H2S concentration in the produced fluid is used as indicator of the injection progress.The injected sour gas has higher H2S concentration (around 16%-22%) than the original oil at 12%.The EOR project was considered a success based on low production levels of injected sour gas of 2%in 2010 and 3.5%in 2014,excellent voidage replacement of 110% in 2010 and 250% in 2014, as well as good reservoir pressure maintenance of 59.7 MPa in 2010 and 54 MPa in 2014 [53,77].

Fig.4.a: Sour Gas Injection (SGI) Area - Relative production and injection volumes and b: Storage of sulfur in Kazakhstan [76].

Fig.5.Areal map of Tengiz with sour gas injection patterns [56].

TCO’s net daily production in 2017 was 544,000 barrels of crude oil,802 million standard cubic feet of natural gas and 42,000 barrels of NGLs [78].The majority of the producing wells have water cuts less than 1% [79].It has 1,574 million barrels proved developed reserves and 1,924 million barrels proved undeveloped reserves.The Sour Gas Injection with Second Generation Project plant doubled the previous level of production.

The Future Growth and Wellhead Pressure Management Project,with first oil expected in 2022,will increase the daily production to 520,000 barrels of crude oil and expand the injection of sour gas into the reservoir[78].This project location is shown by the green pattern area in Fig.5, which shows the existing 5-spot sour gas injection area [56,78].

Currently sour gas is injected in the central platform, which is more suitable for sour gas injection due to higher average porosity(8%)and fewer fractures.The wells on the flanks have lower storage capacity with average porosity of 4%;nevertheless,they have higher production rates due to a greater number of natural fractures[55].The future injection plans include injection into the flanks of the reservoir.The sector model of 15.2%of the field area,which includes existing wells(T-6,T-104,T-110)and future wells(T-4838)[52]was simulated for four different injectants: water, CO2, sour gas, and nitrogen.CO2has low critical temperature (87.8°F) and pressure(1,070.4 psi)therefore,it behaves like liquid at reservoir conditions and would be heavier than Tengiz oil, creating gravity underride(low viscous to gravity ratio).CO2and water act as potential good candidates for injection into the flanks,with a voidage replacement ratio of 1.Unfortunately,CO2is not economic at Tengiz.The gaseous injectants will create gravity override(low viscous to gravity ratio)and will have lower voidage replacement ratio(92-94%)due to gas breakthrough in the fractures[6,56,80,81].

4.Future application of EOR in Kazakhstan

Despite numerous ongoing EOR projects in Kazakhstan,there is still considerable potential for improved recovery in the country.The fields discussed above have significant future EOR production with ongoing development phases and there are many smaller oil fields that do not currently have EOR development.A major targetfor future EOR is the development of the retrograde gas condensate reservoirs of Kazakhstan.

Several factors can contribute to a limited recovery factor in retrograde gas condensate reservoirs, with pressure drop being the most significant.As reservoir pressure decreases, the dew point is reached and condensate begins to drop out [82].This reduces the relativepermeabilityto gasin thereservoir.Laboratorystudiesindicate that a significant decrease in gas permeability of 60%-84%could occur before the critical condensate saturation(Scc)required for condensate to flow is reached[83].The Scccan range from 1%to 40%depending on reservoir permeability and interfacial tension conditions[84].

EOR methods such as solvent,chemical,and gas injection can be employed to increase the recovery from gas condensate reservoirs[85].CO2injection is of special interest due to its role as a greenhouse gas.Jessen and Orr [86] suggest that the low miscibility pressures found in the CO2injection process may indicate the applicability of CO2injection even in depleted condensate reservoirs.In the case of tight gas condensate reservoirs, core flood experiments indicate that cyclic CO2injection can improve condensate recovery by nearly 5%over methane injection[87].This indicates CO2flooding or cyclic CO2injection potential for enhanced recovery in a variety of condensate reservoirs.

4.1.Karachaganak condensate field

Karachaganak is a giant carbonate Late Devonian to Early Permian-age retrograde gas condensate reservoir in western Kazakhstan (See Fig.1).It was discovered in 1979 and production began in 1984.Karachaganak has 17.8 billion barrels of oil equivalent original hydrocarbons in place [88], and produces 50 million cubic meters per day of gas (half of which is reinjected) and 256,000 barrels per day of condensate.The field is currently operated under a 40-year production-sharing agreement signed in 1997 by Karachagank Petroleum Operating Company, a consortium of international and national oil companies [3].

Key parameters describing Karachaganak reservoir are shown in Table 6.These characteristics produce a variation vertically in the reservoir from shallow gas to deeper oil.The produced fluids have a high sulfur content[88],which presents significant issues with the operation and development of the reservoir.

In the long term,as pressure continues to deplete,application of EOR methods will need to be considered to best produce the remaining hydrocarbons in Karachaganak.CO2injection is a good method to consider,especially as CO2capture technology improves.This would allow for additional recovery from the reservoir.Further analyses of the interactions of Karachaganak reservoir rock and fluid with CO2is recommended before significant investment in CO2flood technology occurs to ensure technical and economic feasibility.

5.Conclusions

Current enhanced oil recovery in Kazakhstan is dominated by sour gas reinjection methods.Sour gas reinjection is a preferred method in many reservoirs due to the high production rate of H2S and lack of sufficient markets to sell sulfur.Among all sour injection projects, the Tengiz EOR project is considered a success based on low production of injected sour gas,excellent voidage replacement,and sufficient reservoir pressure maintenance.On the other hand,Kashagan Field presents a very challenging situation regarding not only operational but also environmental aspects, which makes its development uniquely difficult.In this field, more specific assessments should be performed to guarantee that the risk of asphaltene precipitation is minimized in the sour gas injection process.

Other EOR methods in use on a large scale include a variety of thermal methods as well as a pilot polymer injection project.Thermal EOR methods have been in use in some of the mature heavy oil fields in the country for decades.These projects have effectively lowered the oil viscosity,achieving a desirable mobility ratio and improving displacement efficiency.Regarding polymer injection, it has been implemented since the late 1960s, achieving good results.In particular, a recent project proved successful in Kalamkas on a pilot development level,suggesting that this method could be extended across the field.

Considering the vast number of hydrocarbon reservoirs in the country and the potential for future discoveries and development,there is still significant untapped potential in the country’s current and future hydrocarbon reservoirs.One subject of future EOR development in Kazakhstan is retrograde gas condensate reservoirs,and it is recommended that further research on enhancing recovery from Karachaganak reservoir should be undertaken,including laboratory and pilot testing on the feasibility of CO2injection.

Declaration of competing interests

The authors declare that they have no conflict of interests.

Nomenclature

CO2Carbon dioxide

EOR Enhanced oil recovery

EDMicroscopic sweep efficiency

EVVolumetric (macroscopic) sweep efficiency

H2S Hydrogen sulfide

HPAM Hydrolyzed polyacrylamide

ISC In-situ Combustion

krDrelative permeability of injected fluid

krorelative permeability of reservoir oil

M Mobility ratio

MMP Minimum miscibility pressure

NCaCapillary number

Ppm Parts per million

Rv/gViscous to gravity ratio

SccCritical condensate saturation

μoviscosity of reservoir oil

μDviscosity of the displacing fluid

ν interstitial velocity

ρodensity of reservoir oil

ρDdensity of the displacing fluid

σoDinterfacial tension between oil and the displacing fluid