Guerra, Edilena (Intevep S.A.) | Valero, Emil Margarita (PDVSA Intevep) | Rodriquez, Daniela (Petroleos de Venezuela S.A.) | Gutierrez, Luz (Petroleos de Venezuela S.A.) | Castillo, Maria (Petroleos de Venezuela S.A.) | Espinoza, Javier (Espol) | Granja, Gustavo (Petroleos de Venezuela S.A.)
In design and implementation of Alkali Surfactant Polymer (ASP) formulation for IOR processes, the inorganic alkali component acts as sacrificing agent avoiding the surfactant adsorption and decreasing the IFT. Nevertheless, as a part of this process there are some potential problems to be considered previously and during ASP injection processes such as: the ASP injection water should be softened to prevent scale formation that produces higher costs for water treatment, possible tubing corrosion problems and possible viscosity reduction. The effect of organic alkali on IFT, adsorption and viscosity has been previously focussed on comparing to the conventional inorganic alkali in these formulations. In those investigations, it was founded that organic alkalis are compatible with unsoftened waters and the rest of ASP slug components, reduce adsorption, minimize the surface equipment and the formation damage what reduces initial investment costs and greater project profitability.
The objective of this study is to show the advantages and outcomes in applying an improved design of the current ASP formulation for the pilot project La Salina Field Maracaibo Lake, using an organic compound-surfactant-polymer (OCSP) formulation, which uses an organic compound as substitute for traditional inorganic alkali. In fact, fluid-fluid and rock-fluid compatibility laboratory tests, new chemical components concentrations, phase behavior study, IFT screening and porous media evaluations (adsorption and recovery factors) were performed in laboratory in berea cores. Linear corefloods displacements for La Salina LL-03 let to obtain the OCSP flood recovery and additional OOIP estimated of 22.2%. Finally, these results confirm the technical advantages of applying an optimized formulation using an organic agent for this field.
The ASP technology is an enhanced oil recovery method which combines the synergetic effects of three components (alkali, surfactant and polymer) in order to improve the sweep efficiency to oil residual saturation. This effect is achieved with the reduction of the IFT from the injection of surfactants and alkaline solutions which also acts like sacrificing agent to diminish the adsorption of surfactant and polymer into the porous media. The polymer injection lets to increase the viscosity of ASP slug, which is fundamental to improve the volumetric sweep efficiency.
There are numerous successful international experiences in the ASP technology application. Particularly, those in US and China fields represent the most emblematic experiences 1, 2, 3. La Salina Field, on the eastern coast of Maracaibo Lake in Venezuela, is ASP pilot project designated contemplating all different and crucial stages of this process: development of the corresponding optimal ASP formulation for LL-03/Phase III reservoir, numerical simulation model and design of an injection plant 4.
An estimate of 19.0% was considered as the incremental recovery factor for reservoirs of Miocene with the injection of ASP according to previous studies to optimal ASP formulation. The area of Phase III has been subject to water injection project since 1987. The injection has been carried on by inverted seven spot well patterns. The ASP injection project contemplates to implant the technology in three arrangements initially. The subject tests development in this study corresponds to the first arrangement, where is located the well PB-734. The type of arrangement is a triangular form with a separation between wells of 150 mts aproximately. In the center of the triangle, a well injector of ASP and one observer are located. All these wells were completed with sensors of pressure and temperature of bottom. Figure 1 shows the area of study into the Phase III and the Table 1 lists the reservoir typical characteristics of the LL-03, La Salina.
This paper discusses the recent patent application filed by EnCana Corporation on the use of air injection to improve the performance of steam assisted gravity drainage (SAGD).
EnCana's SAGD/Air Injection process employs standard SAGD well-pair infrastructure. It optimizes between the ability of steam to preheat the reservoir during SAGD and the superior (follow-up) oil displacement efficiency of in-situ combustion.
Operationally, air injection is initiated after thermal communication has been established between well-pairs with steam. One interesting feature of this operating strategy is that down-hole bulk separation of oil and gas occurs which facilitates (a) efficient monitoring and control of the combustion, (b) design of surface facilities, and (c) corrosion mitigation.
Laboratory combustion tube tests are presented that confirm the ability to initiate and sustain combustion, as well as mobilize residual oil saturation to steam, within a SAGD chamber. These experiments were initialized at oil saturations and conditions representative of those in a steam chamber. The residual oil saturations were determined from a full-hole core taken in the vicinity of a mature SAGD well-pair at Foster Creek.
Numerical simulations of post-SAGD air injection are presented that suggest the ability to displace and produce oil banks between well-pairs and that recovery factor can be increased up to 8% of the original oil-in-place over conventional SAGD.
The simulations show oil production rates and recovery factor are expected to increase with higher air injection rates. However, instantaneous air-oil ratios, which are indicative of operating costs, also increase. Thus there is an optimum continuous air injection rate that maximizes profitability. Simulations further indicate that it is possible to recycle flue gases in the injection stream without affecting oil recovery.
Bellorin, William Enrique (Petrobras Energia de Venezuela) | Castillo, Jose Antonio (Petrobras Energia de Venezuela) | Lopez Kovacs, Sonia Isabella (Petrobras) | Riera, Ladimir Alberto (Petrobras Energia de Venezuela)
The study area has produced over 457 MMBbl of oil since its discovery in 1954. This study is focused on the R sand reservoir, one of the most important of the area. The original oil in place (OOIP) is 140 MMBbls and before the begining of the project, the accounted recovery of OOIP was 7.2%.
The field reactivation was performed after a thorough analysis that included a geological model review and creating a numeric simulation model. This resulted in an increment of the field production which reached up to 7000 Bbls/d of oil and an enhanced recovery factor of 13.6% by March 31st, 2005.
The main producing zone of the study area comprises Early to Mid Miocene (Oficina Formation); it is interpreted as interbedded sandstone, deposited in a fluvial environment with marine to shallow marine influence. Core analysis in one well shows that R sand was deposited in coastal plain influenced by tides and characterized by connected channels and outlets. The 3D seismic information available in the area made it possible to accurately define the structural model. After defining the static model and with the support of the engineering study, the reservoir development plan could be defined, which was oriented to improve and to increase the field productivity. It mainly consisted in drilling horizontal wells where succesful results were obtained after drilling and completing seven wells. This shows the impact of this type of wells in terms of economic benefits resulting in an increment in production and the recovery factor.
The study area, is located approximately 400 km to the south east of Caracas, in the Area Mayor de Oficina. Structurally, the field is located in the southern flank of the Eastern Venezuelan Basin, in the foreland platform zone (Parnaud et al., 1995) (Fig. 1). The reactivation project of the R Sand reservoir resulted from a previous study of characterization that allowed elaborating a plan of operation constituted mainly by horizontal wells producing with high volume electrical submersible pumps from 7,000 to 20,000 BFPD. To date 7 horizontal wells throughout the reservoir have been drilled; they produce between 300 and 1100 BPPD. At the end of 2003 an electrical submersible pump with capacity to produce 20,000 BFPD was installed representing the first in its class of Petrobras in Venezuela. The definition of the stratigraphic and the structural model as well as the simulation of the reservoir played an important role in deciding the location of the horizontal section of wells. The reservoir is delimited to the south by a main fault east-west oriented, that has a vertical throw of 400 feet, to the north a water oil contact at -6760 feet, to the east by a secondary fault of direction NE-SO of 280 feet of vertical throw and to the west by a structural closure against the main fault of the area.
The producing sands of the Oficina Formation of which the R sand is part of, are included in a foreland megasequence of the Maturin Sub basin which in turn is part of the Eastern Venezuelan Basin (Fig. 1). This Neogene foreland basin is superposed to a Mesozoic passive margin (Di Croce, 1995). The Eastern Venezuelan Basin is subdivided in the Guárico and Maturin Sub basins; they are separated by the Anaco fault system (Di Croce, 1995). The South and east limits of the Eastern Venezuelan Basin are, respectively, the Guayana Shield and the Deltana Platform (Di Croce, 1995). The Maturin Sub basin constitutes the main hydrocarbon unit of the basin. To the south of this Sub-basin, the important reservoirs are in the Merecure and Oficina Formation (Fig.2), with seals of shale within these units overlain by an important and extensive seal of shale of regional character corresponding to the Freites Formation (Upper Miocene). The API gravity of the crude is very diverse, varying from light crude to heavy and extra-heavy crude. As to the oil systems of the Maturin Sub basin, one of the most important ones is the denominated Guayuta-Oficina that is related to the fields of the South flank of the sub basin and includes the main source rocks of Late Cretaceous age, Querecual and San Antonio Formations.
A three-parameter model relating the decline of the oil cut with the fractional oil recovery for waterflooded petroleum
fields or reservoirs is described. The model is based on observation of the behavior of several Brazilian oil fields, in which the oil displacement occurs either by water injection or by natural aquifer influx, or both.
The model is used to derive equations to forecast the oil and water production rates in waterflooded systems. These equations may also be used to design a waterflood expansion in any phase of a field's life.
An example of the application of the model equations to forecast the behavior of a waterflood in a mature heavy oil
field is presented. Because the results of the analysis indicated that the field will still be profitable at the end of the concession period, the model equations are applied to design and forecast an augmented waterflood for the field.
The model equation may be used to estimate the oil reserves at any stage of maturity of an oil field.
The model parameters are obtained by fitting the model equation to historical field data by means of a least square
algorithm. A type-curve procedure is applied to obtain the initial guesses of the model parameters required by the
A relation between the oil cut decline model and the classical rate-time decline is derived for the case in which the total
liquid flow rate is constant.
Examples of oil cut decline of several Brazilian fields are presented and the decline model is used to determine the
ultimate oil recoveries of these fields. The ultimate oil recovery is proportional to the amount of water produced
during the field's life, which is related to the water-oil ratio at abandonment conditions.
When the operating conditions of a field change, so does the oil-cut decline trend. An example of the change in the oil-cut decline trend is presented for a heavy oil field submitted to a late steam drive.
Water injection and natural water influx are very effective mechanisms to displace oil towards the production wells and
to maintain the reservoir pressure. Due to the nature of multiphase flow in porous media, such mechanisms always
lead to an increasing water-oil ratio in the producing wells. Forecasting both oil and water rates is of utmost importance
for the design and implementation of waterflood projects in the several phases of the field's life.
Historical data of oilfields show that it is possible to keep the oil throughput nearly constant for very long time by
continuously increasing the water injection rate. For instance, by keeping constant bottom-hole pressures in both producers and injectors wells, the increase in the liquid rate is natural in heavy oil fields, since the low mobility oil is displaced by the high mobility chasing water. Infill drilling also helps to increase the injection rate, and consequently the total liquid production, due to the increase in the reservoir pressure gradient. In both cases, there is an increase in the drainage velocity and, when the capillary and gravitational effects are small, the ultimate oil recovery will not be affected by increasing the drainage velocity. In this case the increase in the water injection rate anticipates the oil recovery.
Here we use simple methods to extrapolate the oil cut in order to forecast the capacity of the surface facilities required to handle the produced water, once a restriction in produced water rate leads to a decrease in the oil production rate.
In fields under water injection or water drive mechanisms, the water breakthrough occurs after a period of primary
production, where a given fraction of the initial oil in place is recovered. This period is followed by both a continuous
increase in the water-oil ratio and a continuous reduction in the oil cut.
Arps1 presented a hyperbolic equation to describe the decline of the oil rate with time. Such equation has shown to be ofrestricted use for waterflooded reservoirs, where an infill drilling campaign can even cause an increase in the oil rate.
However, even in this scenario the oil cut always decline.
The objective of this study is to investigate the advantages of drilling horizontal wells on oil recovery improvement. To evaluate the effect of horizontal length, porosity, anisotropy, staggeredline well pattern with gas injection (in the top layer) and water injection (in the bottom layer), different scenarios were studied.
This study is focused on simulation of formation-A of a carbonate reservoir which consists of three layers; where horizontal well is going to be drilled in layer-2 of this formation. The average thickness of formation-A is about 167.64 meters (550 feet) and we also have tilted water oil contact in this formation.
This field has produced around 146.9 MMBBL until year 2002 for the last 12 years with the Recoverable Reserve of about 237.31 MMBBL. Up to now 40 wells have been drilled in this field.
IRAP/RMS software was used to generate geological model. Based on selected reservoir black-oil model, IMEX from CMG is used for
simulation task. Sector model used for simulation as we only had one productive horizontal well in the formation (scale-down method).
This study confirms simultaneous use of overbalance method and horizontal well in this reservoir in order to: A) Increase production rate up to 3 to 4.5 times by boosting productivity index (PI). B) Communicate a large area leading to a better drainage area. C) Postpone the water breakthrough by minimizing the draw down pressure.
To identify the key factors controlling the impact of drilling new horizontal well at the reservoir scale are always a fundamental issue. Once this identification is done, simulation model will allow determination of which combination of vertical and horizontal wells will be the most suitable drilling activity in order to enhance the production. The impact of a horizontal well on the reservoir will depend on many factors. This includes the number of existing wells, well spacing, formation thickness, Kv/Kh, type of drive mechanism, completion
intervals of vertical wells, well radius, drainage radius, oil viscosity (and other PVT properties) and obviously the length and placement of horizontal wells. The aim of this study is to assess effect of horizontal well performance on boosting oil recovery. A case study from one of Iranian reservoirs is simulated.
Many works on dynamic models for the maximization of the Net Present Value (NPV) on upstream projects have been published in recent years, originating in the academy as well as the industry. These models usually treat the effort considering either the exploration stage or the development stage of the petroleum field, but not both together. In this paper, two purposes will be pursued: (1) Investigating of the optimum net present value in the upstream project considering both exploration and development efforts simultaneously, and (2) Comparing the impact of this model against the dynamic models that deal with the sustainability of the exploration of exhaustible resources according to Hotelling's rule (1931). On the first topic, some papers were published by Pakravan (1977), Peterson (1978), Pindyck (1978), Liu and Situnen (1982), and Nilssen and Nystad (1986). The present paper shows a model bearing resemblance to the model proposed by Nilssen and Nystad (1986) but without the simplifications assumed by it. For this reason, the model proposed here may be more realistic. Some of the questions addressed in this work are: (a) What is the optimum exploratory effort for a petroleum field? (b) For how long do the exploratory efforts deserve investment before the beginning of the development stage? (c) What is the appropriate value of the reservoir recovery factor? The maximization of the NPV is represented by an objective function. The influence of the parameters in the calculation of the proposed objective function is shown by means of sensitivity analysis. Among the the companies in the world exploring petroleum, several do not usually adopt a methodology combining the exploration and development efforts. Filling this gap in the methodology is the main motivation for this work, which intends to disseminate the use of the combined model in the analysis of the economic viability project of the upstream area. Finally, in the conclusion section, among other suggested guidelines, indications are given as to which parameters from this model deserve more attention from persons making hard decisions in the upstream projects, and which information from the exploration and development of a petroleum field must be collected from existing data, or specially treated.
The present work has two main purposes: (1) investigating the optimum exploration and development effort of a petroleum field by the maximization of the net present value of the investment, and (2) comparing the impact of this maximization model against the dynamic models used in activities of exploitation of exhaustible resources, particularly the Hotelling model (1931). The optimum effort, both in the exploration and the development stages, is simultaneously assessed. This type of modeling is not yet widely used in the petroleum industry; instead, these maximizations are in general treated separately. The issues in any search for optimization of exploration and development activities are: (a) what is the optimum exploratory effort of a field, expressed in number of wells? (b) how much time should be invested in the exploration of a field before starting development proper? (c) which optimum rate of the field reserve should be extracted per year? Of course some simplifying assumptions will be made, in order to allow appropriate simulations of the models, but care will be taken not to distance the model from reality. The first assumption is that there is a relationship between the value of the discovered reserves of a petroleum field and the exploratory effort spent in the discovery. This is reasonable, and it is observed in practice by all hydrocarbon exploration and production companies in the world.
Both in the academic environment and in exploration and development projects prepared by companies, it is common to find models that deal with exploration and development optimization efforts in a segregaded way. One of the reasons for this is the complexity in information treatment demanded by each stage. A combined treatment of both efforts is certainly possible, although the parameters needed for a combined model are difficult to measure. The concluding section indicates which parameters must be more accurately determined by those specializing in assessing E&P projects in petroleum companies. Some important works published on this topic are: Liu and Situnen (1982), Pakravan (1977), Peterson (1978), Pindyck (1978), and Nilssen and Nystad (1986). The model adopted in the present work has similarities to that published in 1986 by Nilssen and Nystad, but some of the simplifying assumptions of these authors were dispensed with. It is believed that this can confer a greater adherence to reality than recently published models.
Paez Yanez, Pablo Adrian (Pan American Energy) | Mustoni, Jorge Luis (Pan American Energy) | Frampton, Harry (BP Exploration Co. Ltd.) | Relling, Maximo F. (Nalco Company) | Chang, Kin-Tai (Nalco Energy Services Division) | Hopkinson, Paul Christopher (BP Amoco Corporation)
Most of the mature waterflood projects at the San Jorge Basin have been affected by two main problems, poor displacement and sweep efficiencies, both have limited the recovery factor achievable.
This paper presents a field trial of a new reactive particulate system in an attempt to improve this volumetric sweep efficiency. This particulate system is being used to treat selected injectors operated by Pan American Energy in the Koluel Kaike and Piedra Clavada fields, located in the southern part of Argentina. The main purpose of this field trial is to demonstrate the ability of the new system to improve oil recovery by diversion of injected water into the poorly swept zones around the thief zone or streaks.
This state-of-the-art technology is able to propagate deep into thief zones and has a novel mechanism of action to overcome the observed limitations in conventional polymer flooding and gel processes. The particles are manufactured having properties which allow it to propagate through porous media with the injection water. Once in the reservoir and under the influence of heat the particle expands to a size that can block pore throats, so water injected after treatment is diverted into less efficiently swept zones.
The paper will describe in detail the mechanism and selection criteria of reservoirs and wells to apply the mentioned IOR technology. Theoretical and practical issues involved at the design of the application, as well as operational and logistics aspects will be also included. Finally, it will include the updated information available from the ongoing pilot tests.
Koluel Kaike and Piedra Clavada fields are located at the Southern flank of the San Jorge Gulf Basin, in the province of Santa Cruz, Argentina (Figure 1).
Figure 1. Koluel Kaike and Piedra Clavada Areas Location Plat
Both fields are currently being operated by Pan American Energy and together with Cerro Dragon Field form one of PAE's Business Units. These two fields were discovered in early 1960s and exploited under primary depletion up to mid 1980s. Since this date, a massive waterflooding process has been initiated to increase the relatively poor primary recovery. It has involved about 220 injectors, with an operation rate of 250 cmpd (1600 bwpd) per injector, affecting 500 producers. Through the 20 years of waterfloood operation a total of 300 million cubic metres (1900 million barrels) of water have been injected and resulted in an incremental recovery estimated as 12 million cubic metres (75 million barrels) of oil, through December 2006 (Figure 2 & Figure 3).
This mature waterflood project, as any other of the San Jorge Basin, has been affected by both main problems that have limited the recovery factor achievable. These are the poor displacement and sweep efficiency, characteristic of the San Jorge Basin reservoirs.
In naturally fractured reservoirs (NFRs), current analyses for quantifying reserves based on the material balance equation (MBE) assume that fractured reservoirs behave similar to homogeneous reservoirs, which implies that the fracture and matrix pore volume compressibilities are equal. There is considerable evidence that such assumption is not always valid leading to wrong estimation of reserves. In order to overcome this deficiency a complete treatment of the material balance formulation for naturally fractured reservoirs is presented. The proposed general MBE takes into account the fact that fracture and matrix pore volume compressibilities are different. This equation is used to investigate the impact of pressure depletion on the estimation of oil in place and recovery factors.
As results of this study, new equations to compute hydrocarbons originally in place in NFRs are developed for undersaturated and saturated reservoirs. New plotting schemes for the MBE involving the storage capacity ratio at initial reservoir conditions of fracture and matrix pore volume compressibilities are proposed. The capacity ratio is computed from pressure transient test performed during the early stages of production. These new plotting schemes requires only one regression parameter, the slope of a straight line passing through the origin on a Cartesian plot, which reduces the uncertainty that traditionally two regression parameters (intercept and slope) introduces; as consequence, better estimation of oil in place with fewer historical production data can be obtained. This new method is illustrated by several field examples.
It is concluded that (a) the proposed material balance formulation gives better estimation of oil in place than the traditional MBE computations; (b) the split of hydrocarbons originally in place between fracture and matrix frames depends upon the storage capacity ratio at initial reservoir conditions and; (c) the impact of pressure depletion on the estimation of reserves and recovery factors in naturally fractured reservoirs is significant.
This paper presents methods to quantify hydrocarbons in place and recovery factors taking into account the differences between fracture and matrix pore volume compressibilities, and their changes caused by pressure depletion for undersaturated and saturated naturally fractured reservoirs. Such methods are based upon the integration between pressure transient analysis and the material balance equation.
For undersaturated reservoirs, the assumption that matrix and fracture pore volume compressibilities are equal leads to underestimations of the fractional recovery. For saturated reservoirs only negligible differences in estimation of reserves and recovery factors have been observed.
The General Material Balance Equation for Naturally Fractured Reservoirs
The link between the elastic behavior of the rock and the recovery predictions in the material balance modeling resides in the effective compressibility term and the storage capacity ratio. Therefore, to model the effect of changes in stress due to changes in pore pressure in the fracture system, the general volumetric material balance equation must be modified using the correct effective compressibilities of the fracture rock.
The general MBE, initially presented for homogeneous reservoirs by Schilthuis1, has been improved by Chacon2 to take into account changes and differences in fracture and matrix pore volume compressibilities in naturally fractured reservoirs.
In line with the time available to introduce a development plan for several fields in eastern Venezuela with low reliability in the production data, it was decided to evaluate the remaining power of the field by a dynamic modeling using a one-dimensional simulator (Peron, SPE-94723-PP). During the model development, the analysis showed inconsistencies in the gas production data. The methodology of correction is analyzed in this paper. Production -primary and secondary- forecasts were performed and employed to approve the field operation plan.
After approving the field development plan under this methodology and due to time constraint while the project was being implemented for sands L, M and N (35% of the remaining reserves of the field) a conventional numeric simulation was performed to increase the reliability of the previous forecasts. The conventional simulation considered the original and the corrected production data from the one-dimensional simulation in order to compare the effects in the historical adjustment.
This paper is intended to show a contrastive analysis of the results in both cases. Also, to evaluate the advantages and disadvantages of the one-dimensional simulation methodology defining the parameters that show uncertainty when it comes to analyze a field (size of the aquifer, formation of the secondary gas cap, relevant production mechanism, dispersion level of phases, trend towards channeling and coning).
The Field is located in the Eastern basin of Venezuela. The operation of the field began in 1938 with the wildcat P1 and up to date a total of 60 wells have been drilled. At present, it produces 2500 of oil barrels daily with an average of 16 active wells (Figure 1).
It has an accumulated production of 26 MMBbls in about 60 productive levels. The total OOIP of the field is 238 MMBbls with a 10.8% of recovery factor.
For maximizing the final recovery factor it was made a static characterization and a numerical simulation of the main sands with the objective of defining the best scheme of operation to drain efficiently the remaining reserves.
The Field is considered mature and is characterized for the presence of many layers with several reservoirs that, in some cases, can be total or partial communicated among them. In addition, the production history is not precise. Errors in the gas production reports and for the first years only cumulative oil and water production are available. These facts cause that the conventional simulation process be time consumer with unpredictable results.
To estimate the remaining potential of mature fields with multiple reservoirs is a task that can consume much time with uncertainty. Like an aid in these cases and based on the commitment to generate a development plan of the field in an established period, a one-dimensional simulation (Peron, SPE-94723-PP) was made for defining the potential of remaining primary and secondary production.
Once the project was approved and within the established time, the results previously obtained were validated with conventional numerical simulations
The objective of this work is to present the application of the one-dimensional simulation and to make a comparative analysis of the results obtained between this and the conventional numerical simulation. Additionally, to present the advantages of using this tool in the validation of parameters that present uncertainty at the time of analyzing a reservoir.
The Bati Raman field is the largest oil field in Turkey and contains some 1.85 billion barrels of oil initially in place. The oil is heavy (12 oAPI) with high viscosity and low solution gas. Primary recovery has been inefficient, less than 2% of OOIP.
Over the period of primary recovery, from 1961 to 1986, the reservoir underwent extensive pressure depletion from 1,800 psig to as low as 400 psig in some regions, with a related production decline from a peak of approximately 9,000 Bbls/day to 1600 Bbls/day.
In March 1986, a CO2 injection pilot scheme in a 1200 acre area containing 33 wells was initiated in the west portion of the field. The gas injection was initially cyclic; "huff and puff?? method was applied. Later, in 1988, the gas injection scheme was converted to a CO2 flood process. Later, the process was widespread to cover the whole field.
A peak daily production rate 13000 STB/d was achieved in 1993 in comparison to what would have been less than 1600 STB/d without CO2 application. However, since 1995, the field has undergone a progressive production decline to recent levels at approximately 5,500 Bbls/day. Polymer gel treatments were carried out to increase the CO2 sweep efficiency and arrest the decline. Multilateral and horizontal well technology was also applied on pilot scale to reach the bypassed oil. WAG is applied widespread now. Current production is 7000 Bbls/day.
This paper documents TPAO's 25+ years of experience on the design and operation of full field immiscible CO2 injection recovery project conducted in the B.Raman heavy oil field, in Turkey. The objective is to give an up-to-date status of the performance of the application; reservoir/field problems that TPAO had, unexpected occurrences and results and just a general idea of how successful the project has been.
The Bati Raman field, which is the known highest oil accumulation in Turkey, contains very viscous and low gravity oil in a very challenging geological environment. Due to the fact that the recovery factor by primary recovery was limited, several EOR techniques had been proposed and tested in pilot level in the 70s and 80s. Based on the success in the lab tests and vast amount of CO2 available in a neighboring field which is just 55 miles away from the Bati Raman field, field scale huff-and puff injection was started in the early 80s. Due to the early breakthrough of CO2 in offset wells in a short period of time, the project was converted to field scale random pattern continuous injection. Over more than 20 years of injection, the recovery peaked at ~13,000 bbls and began to decline reaching today's ~7,000 bbl value.
In the case of Bati Raman, at this mature state of the process, the injected agent is increasingly bypassing the remaining oil and production is curtailed by excessive high gas oil ratios (GOR). The naturally fractured characteristics of the reservoir rock has been a challenge for establishing a successful 3D conformance from the beginning and its impact is even more pronounced in the later stages of the process. Because of that reason, the subject field requires modification on the reservoir management scheme to improve recovery factors as well as improving productivity of the current wells.
BATI RAMAN FIELD
Bati Raman was discovered in 1961 in Southeastern Turkey with the completion of BR-1 (Fig-l). The producing formation is the Garzan Limestone, a very heterogeneous carbonate of Cretaceous age. The reservoir fluid is a very heavy crude oil, having an API gravity ranging from 9.7 to 15.1 and a viscosity ranging from 450 to 1000 centipoises at reservoir conditions.
The structural trap is a long; partly asymmetric anticline oriented in the east-west direction which measures about 17 km. long and 2 to 4 km. wide. It is limited by an oil/water contact at 600 meters subsea in the north and west, by a fault system in the southwest and south, and by a permeability barrier in the southern and southeastern part of the field. Formation has a gross thickness of 210 ft (64m). The oil column from the top of structure to the OWC is about 690 ft.