Five-spot Pattern Research Articles

Sensitivity analysis and economic optimization studies of inverted five-spot gas cycling in gas condensate reservoir

Abstract Gas condensate reservoirs usually exhibit complex flow behaviors because of propagation response of pressure drop from the wellbore into the reservoir. When reservoir pressure drops below the dew point in two phase flow of gas and condensate, the accumulation of large condensate amount occurs in the gas condensate reservoirs. Usually, the saturation of condensate accumulation in volumetric gas condensate reservoirs is lower than the critical condensate saturation that causes trapping of large amount of condensate in reservoir pores. Trapped condensate often is lost due to condensate accumulation-condensate blockage courtesy of high molecular weight, heavy condensate residue. Recovering lost condensate most economically and optimally has always been a challenging goal. Thus, gas cycling is applied to alleviate such a drastic loss in resources. In gas injection, the flooding pattern, injection timing and injection duration are key parameters to study an efficient EOR scenario in order to recover lost condensate. This work contains sensitivity analysis on different parameters to generate an accurate investigation about the effects on performance of different injection scenarios in homogeneous gas condensate system. In this paper, starting time of gas cycling and injection period are the parameters used to influence condensate recovery of a five-spot well pattern which has an injection pressure constraint of 3000 psi and production wells are constraint at 500 psi min. BHP. Starting injection times of 1 month, 4 months and 9 months after natural depletion areapplied in the first study. The second study is conducted by varying injection duration. Three durations are selected: 100 days, 400 days and 900 days. In miscible gas injection, miscibility and vaporization of condensate by injected gas is more efficient mechanism for condensate recovery. From this study, it is proven that the application of gas cycling on five-spot well pattern greatly enhances condensate recovery preventing financial, economic and resource loss that previously occurred.

Evaluating the critical performances of a CO2–Enhanced oil recovery process using artificial neural network models

CO2 flooding has attracted particular interest as an effective method in enhancing oil recovery (EOR) because it can significantly improve the oil production and assist in the reduction of carbon emissions from anthropogenic sources by permanently storing the injected gas in geological formations. The applications of hybrid smart tools on evaluating the uncertainties of CO2-EOR projects have been proposed in many studies; however, the model must still be developed in terms of either the architecture or algorithm to more comprehensively and accurately predict the flooding processes. This study aimed to assess the applicability of neural network models (ANN) on forecasting the essential performances of the multi-cycle water-alternating-gas process including the oil recovery factor (RF), oil rate, gas oil ratio (GOR), accumulative CO2 production and net CO2 storage in a specific five-spot pattern scale after a series of injection cycles. A total of 223 numerical samples were simulated and collected to train the networks with the independent variables being the initial water saturation, the vertical-to-horizontal permeability ratio, the WAG ratio, and the duration of each cycle. The results presented excellent accuracy in terms of the oil recovery factor, the cumulative CO2 production and the CO2 storage network model on estimations with overall root mean square errors of less than 3%, while the errors were much greater for unqualified models of the oil rate and GOR. By using the neural networks generated, the optimal injection designs were determined for various reservoir conditions from both technical and economic point of views. Technically, optimized CO2-to-water injection time ratios (WAG) vary according to different reservoir conditions and different targets involving oil recovery and net CO2 sequestration, while the duration of one injection cycle is most favorable at the upper constraint. Nevertheless, with a specific fiscal system, the maximal profit is, however, achieved at the minimal duration and at a WAG less than 1.5 for possible oil prices from 30 $/bbl to 60 $/bbl. Even though the results will differ for dissimilar EOR projects and economic conditions, the proposal of applying traditional ANN models, as in this work, will significantly support the numerical evaluation of CO2-EOR projects compared to conventional procedures.

Integrating Enhanced Oil Recovery and Carbon Capture and Storage: Farnsworth Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180408, “Integrating Enhanced-Oil-Recovery and Carbon-Capture-and-Storage Projects: A Case Study From Farnsworth Field, Texas,” by Robert Balch, New Mexico Institute of Mining and Technology, and Brian McPherson, University of Utah, prepared for the 2016 SPE Western Regional Meeting, Anchorage, 23–26 May. The paper has not been peer reviewed. The Southwest Partnership on Carbon Sequestration (SWP) is one of seven large-scale demonstration projects sponsored by the US Department of Energy. The SWP has a goal of permanently sequestering more than 1 million t of carbon dioxide (CO2) in an active enhanced-oil-recovery (EOR) project in a mature waterflood in the Anadarko Basin. Goals of the project include optimizing the balance between EOR and storage, ensuring storage permanence, and developing best practices for carbon storage using man-made CO2. Introduction The goal of the project is to inject at least 1 million t of CO2 into an active oil field undergoing EOR over a 4- to 5-year period. All CO2 used in the project is anthropogenic and would otherwise be vented to the atmosphere. Much of this injected CO2 will be trapped permanently in the subsurface. A primary objective is to quantify CO2 storage and better understand conditions and characteristics that promote such storage. Background. The project site is located in the Anadarko Basin, a deep structural basin approximately 70,000 sq miles in size and primarily located in the northern Texas panhandle and western Oklahoma and extending into eastern Colorado and western Kansas. The basin is a mature oil-and-gas-production province but without access to natural CO2 sources. These factors combine to make the Anadarko an excellent region for combined EOR and carbon-storage projects using anthropogenic CO2. The target formation for the CO2-storage study addressed by this paper is the oil-bearing upper Morrow sandstone, informally designated the Morrow B. The Morrow Formation at Farns worth is an incised valley filled with coarse sandstone that has produced more than 19 million bbl of oil and 44 Bcf of gas. The formation lies at an average depth of 7,750 ft and contains rock with permeability ranging from 10 to 500 md, placing it well within the range needed for CO2 injection and storage. Preliminary estimates of CO2-storage capacity of the Morrow within the Farnsworth Unit (FWU) exceed 25 million t. To date, all CO2 has been delivered from two anthropogenic sources. Much of this injected CO2 is being trapped permanently in the subsurface in the Morrow B formation. The site operator is injecting CO2 in the center well of five-spot well patterns. The project started with three initial patterns in December 2010, and more patterns are to be added as CO2 is purchased and more recycled CO2 becomes available. As of May 2015, there were 13 operating patterns. The plan is to have approximately 25 patterns in operation.

A framework for assisted history matching and robust optimization of low salinity waterflooding under geological uncertainties

Low Salinity Waterflood (LSW) is an emerging Enhanced Oil Recovery (EOR) method that is simple to implement and has been shown to yield a substantial increase in oil recovery over conventional waterflood, especially in oil-wet sandstone reservoirs. The major mechanism for increased oil recovery is a wettability change from oil-wet to water-wet, which is induced by ion exchange between the injected fluid and the clay surface.This paper presents a framework for field scale modeling, assisted history match, and robust optimization of LSW under geological uncertainties that has rarely been discussed in the past. To handle this complex recovery process, a comprehensive ion-exchange model has been implemented, fully coupled with geochemistry specially designed for the modeling of LSW physical phenomena in an EOS reservoir simulator. This model is capable of accounting for the critical role of the properties, quantity, and distributions of clay minerals.A systematic study was performed to evaluate the critical effects of geology on large scale LSW performance. Numerous geostatistical realizations of a five-spot LSW pattern were generated to evaluate the effect of clay on LSW. The numerical simulation results indicate that LSW's performance depends critically on the reservoir geological characteristics. Based on the integrated modeling approach presented in this paper, multiple geological realizations can be automatically generated from a big-loop approach that is needed for fast and accurate HM and optimization of LSW. The key parameters for successful field scale LSW HM include: clay distribution/quantity associated with different facies, relative permeability modification, wettability alteration thresholds, reservoir minerals, geochemical reactions, and operating conditions. More importantly, LSW HM by tuning reservoir parameters may only lead to poor prediction results, while the integrated modeling approach provides much better forecasting results to true history data.Finally, a new concept for LSW robust optimization under geological uncertainty is introduced and demonstrated with reservoir simulation. As there are uncertainties associated with the geological modeling of the clay distribution, this paper shows how robust optimization can be applied to reduce uncertainties in the LSW optimization through well placement.

Compositional simulation of hydrocarbon recovery from oil shale reservoirs with diverse initial saturations of fluid phases by various thermal processes

We have studied the hydrocarbon production from oil shale reservoirs filled with diverse initial saturations of fluid phases by implementing numerical simulations of various thermal in-situ upgrading processes. We use our in-house fully functional, fully implicit, and non-isothermal simulator, which describes the in-situ upgrading processes and hydrocarbon recovery by multiphase-multicomponent systems. We have conducted two sets of simulation cases—five-spot well pattern problems and Shell In-situ Conversion Process (ICP) problems. In the five-spot well pattern problems, we have analyzed the effects of initial fluid phase that fills the single-phase reservoir and thermal processes by four cases—electrical heating in the single-phase-aqueous reservoir, electrical heating in the single-phase-gaseous reservoir, hot water injection in the single-phase-aqueous reservoir, and hot CO2 injection in the single-phase-gaseous reservoir. In the ICP problems, we have analyzed the effects of initial saturations of fluid phases that fill two-phase-aqueous-and-gaseous reservoir by three cases—initial aqueous phase saturations of 0.16, 0.44, and 0.72. Through the simulation cases, system response and production behavior including temperature profile, kerogen fraction profile, evolution of effective porosity and absolute permeability, phase production, and product selectivity are analyzed. In the five-spot well pattern problems, it is found that the hot water injection in the aqueous phase reservoir shows the highest total hydrocarbon production, but also shows the highest water-oil-mass-ratio. Productions of phases and components show very different behavior in the cases of electrical heating in the aqueous phase reservoir and the gaseous phase reservoir. In the ICP problems, it is found that the speed of kerogen decomposition is almost identical in the cases, but the production behavior of phases and components is very different. It is found that more liquid organic phase has been produced in the case with the higher initial saturation of aqueous phase by the less production of gaseous phase.

Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

Heavy-oil resources represent a large percentage of global oil and gas reserves, however, owing to the high viscosity, enhanced oil recovery (EOR) techniques are critical issues for extracting this type of crude oil from the reservoir. According to the survey data in Oil & Gas Journal, thermal methods are the most widely utilized in EOR projects in heavy oil fields in the US and Canada, and there are not many successful chemical flooding projects for heavy oil reported elsewhere in the world. However, thermal methods such as steam injection might be restricted in cases of thin formations, overlying permafrost, or reservoir depths over 4500 ft, for which chemical flooding becomes a better option for recovering crude oil. Moreover, owing to the considerable fluctuations in the oil price, chemical injection plans should be employed consistently in terms of either technical or economic viewpoints. The numerical studies in this work aim to clarify the predominant chemical injection schemes among the various combinations of chemical agents involving alkali (A), surfactant (S) and polymer (P) for specific heavy-oil reservoir conditions. The feasibilities of all potential injection sequences are evaluated in the pre-evaluation stage in order to select the most efficient injection scheme according to the variation in the oil price which is based on practical market values. Finally, optimization procedures in the post-evaluation stage are carried out for the most economic injection plan by an effective mathematic tool with the purpose of gaining highest Net Present Value (NPV) of the project. In technical terms, the numerical studies confirm the predominant performances of sequences in which alkali-surfactant-polymer (ASP) solution is injected after the first preflushing water whereby the recovery factor can be higher than 47%. In particular, the oil production performances are improved by injecting a buffering viscous fluid right after the first chemical slug rather than using a water slug in between. The results of the pre-evaluation show that two sequences of the ASP group have the highest NPV corresponding to the dissimilar applied oil prices. In the post-evaluation, the successful use of response surface methodology (RSM) in the estimation and optimization procedures with coefficients of determination R2 greater than 0.97 shows that the project can possibly gain 4.47 $MM at a mean oil price of 46.5 $/bbl with the field scale of a quarter five-spot pattern. Further, with the novel assumption of normal distribution for the oil price variation, the chemical flooding sequence of concurrent alkali-surfactant-polymer injection with a buffering polymer solution is evaluated as the most feasible scheme owing to the achievement of the highest NPV at the highly possible oil price of 40–55 $/bbl compared to the other scheme.

Well-pattern investigation and selection by surfactant-polymer flooding performance in heterogeneous reservoir consisting of interbedded low-permeability layer

Surfactant-polymer (SP) flooding has been demonstrated to be one of the most efficient methods of recovering the residual oil in the enhanced oil recovery (EOR) stage. However, the uses of SP flooding in horizontal or vertical well patterns are still being disputed from either technical or economic points of view, particularly in complicated reservoir systems. We investigated the successful application of SP flooding for many well-pattern combinations in a heterogeneous reservoir. A quarter five-spot pattern reservoir model is proposed with three different permeable layers; in particular, the interbedded layer has a much lower permeability than the other layers. The combinations of horizontal injectors and producers possess the most successful EOR processes, especially when the wells are interchangeably located in the high-permeability layers. However, the short-length horizontal-well combination is more preferable than the full-length horizontal-well pattern from the results of a comprehensive evaluation.

Gas channeling control during CO2 immiscible flooding in 3D radial flow model with complex fractures and heterogeneity

Fractures and heterogeneity commonly exist in ultra-low permeability reservoirs, which will cause serious gas channeling phenomena and lead to poor oil recovery during CO2immiscible flooding. CO2water alternating gas (WAG) flooding combined with gas channeling control treatments are recognized as effective approaches to enlarge the sweep efficiency of CO2. Performance of gel systems were evaluated to screen out a high-strength gel which can be utilized as fracture blocking agent. Then, performance of small molecule amines were evaluated to screen out a kind of small molecule amine which can be utilized as rock-matrix blocking agent. Performance evaluation results showed that high-strength gel with 8% modified starch + acrylic amide, 0.05% crosslinking agent, 0.15% initiator and 0.15% stabilizer could be served as fracture blocking agent, while etheylenediamine was proposed as rock-matrix blocking agent which could react with CO2 and generate solid particles to improve the heterogeneity of the reservoirs.To examine gas channeling control effect in actual reservoir conditions, a 3D radial flow model with complex fractures and heterogeneity was designed according to the actual oilfield, and five-spot pattern was employed in the model. Waterflooding, continuous CO2 flooding, and gas channeling control using high-strength gel, etheylenediamine and CO2 WAG flooding were conducted successively in the 3D radial flow model. After a series of treatments, the oil recovery was enhanced by 15.09%, which was significant for CO2 immiscible flooding in the field application. The gas channeling along major fracture and microfractures of the model was effectively controlled by high-strength gel, while fluid diversion could occurred after ethylenediamine injection due to the solid particles which could mitigate gas channeling along relatively high permeability areas of the rock-matrix, and the gas channeling phenomena can be further mitigated by the mobility control ability of CO2 WAG flooding.

Upscaling for Compositional Reservoir Simulation

Summary Compositional flow simulation, which is required for modeling enhanced-oil-recovery (EOR) operations, can be very expensive computationally, particularly when the geological model is highly resolved. It is therefore difficult to apply computational procedures that require large numbers of flow simulations, such as optimization, for EOR processes. In this paper, we develop an accurate and robust upscaling procedure for oil/gas compositional flow simulation. The method requires a global fine-scale compositional simulation, from which we compute the required upscaled parameters and functions associated with each coarse-scale interface or wellblock. These include coarse-scale transmissibilities, upscaled relative permeability functions, and so-called α-factors, which act to capture component flow rates in the oil and gas phases. Specialized near-well treatments for both injection and production wells are introduced. An iterative procedure for optimizing the α-factors is incorporated to further improve coarse-model accuracy. The upscaling methodology is applied to two example cases, a 2D model with eight components and a 3D model with four components, with flow in both cases driven by wells arranged in a five-spot pattern. Numerical results demonstrate that the global compositional upscaling procedure consistently provides very accurate coarse results for both phase and component production rates, at both the field and well level. The robustness of the compositionally upscaled models is assessed by simulating cases with time-varying well bottomhole pressures that are significantly different from those used when the coarse model was constructed. The coarse models are shown to provide accurate predictions in these tests, indicating that the upscaled model is robust with respect to well settings. This suggests that one can use upscaled models generated from our procedure to mitigate computational demands in important applications such as well-control optimization.

Compositional Modeling of Dissolution-Induced Injectivity Alteration During CO2 Flooding in Carbonate Reservoirs

SummaryGeochemical reactions between fluids and carbonate rocks can change porosity and permeability during carbon dioxide (CO2) flooding, which may significantly affect well injectivity, well integrity, and oil recovery. Reactions can cause significant scaling in and around injection and production wells, leading to high operating costs. Dissolution-induced well-integrity issues and seabed subsidence are also reported as a substantial problem at the Ekofisk field. Furthermore, mineral reactions can create fractures and vugs that can cause injection-conformance issues, as observed in experiments and pressure transients in field tests. Although these issues are well-known, there are differing opinions in the literature regarding the overall impacts of geochemical reactions on permeability and injectivity for CO2 flooding.In this research, we develop a new model that fully couples reactive transport and compositional modeling to understand the interplay between multiphase flow, phase behavior, and geochemical reactions under reservoir and injection conditions relevant in the field. Simulations were carried out with a new in-house compositional simulator on the basis of an implicit-pressure/explicit-composition and finite-volume formulation that is coupled with a reactive transport solver. The compositional and geochemical models were validated separately with CMG-GEM (CMG 2012) and CrunchFlow (Steefel 2009). Phase-and-chemical equilibrium constraints are solved simultaneously to account for the interaction between phase splits and chemical speciation. The Søreide and Whitson (1992) modified Peng-Robinson equation of state is used to model component concentrations present in the aqueous and hydrocarbon phases. The mineral-dissolution reactions are modeled with kinetic-rate laws that depend on the rock/brine contact area and the brine geochemistry, including pH and water composition. Injectivity changes caused by rock dissolution and formation scaling are investigated for a five-spot pattern by use of several common field-injection conditions.The results show that the type of injection scheme and water used (fresh water, formation water, and seawater) has a significant impact on porosity and permeability changes for the same total volume of CO2 and water injected. For continuous CO2 injection, very small porosity changes are observed as a result of evaporation of water near the injection well. For water-alternating-gas (WAG) injection, however, the injectivity increases from near zero to 50%, depending on the CO2 slug size, number of cycles, and the total amount of injected water. Simultaneous water-alternating-gas injection (SWAG) shows significantly greater injectivity increases than WAG, primarily because of greater exposure time of the carbonate surface to CO2-saturated brine coupled with continued displacement of calcite-saturated brine. For SWAG, carbonate dissolution occurs primarily near the injection well, extending to larger distances only when the specific surface area is small. Formation water and seawater lead to similar injectivity increases. Carbonated waterflooding (a special case of SWAG) shows even greater porosity increases than SWAG because more water is injected in this case, which continuously sweeps out calcite-saturated brine. The minerals have a larger solubility in brine than in fresh water because of the formation of aqueous complexes, leading to more dissolution instead of precipitation. Overall, this research points to the importance of considering the complex process coupling among multiphase flow, transport, phase behavior, and geochemical reactions in understanding and designing schemes for CO2 flooding as well as enhanced oil recovery at large.

Assessment of solubility and viscosity of ultra-high molecular weight polymeric thickeners in ethane, propane and butane for miscible EOR

Natural gas liquid (NGL), a mixture consisting primarily of ethane, propane, and butane, is an excellent enhanced oil recovery (EOR) solvent. However, NGL is typically about ten times less viscous than the crude oil within the carbonate or sandstone porous media, which causes the NGL to finger through the rock toward production wells resulting in low volumetric sweep efficiency in five-spot patterns or during a linear drive displacement. The viscosity of candidate polymeric NGL thickeners is measured with a windowed, close-clearance falling ball viscometer, and an expression for the average shear rate associated with this type of viscometer is derived. High molecular weight polydimethyl siloxane (PDMS, Mw 9.8 105) can thicken ethane, propane and butane, but the viscosity enhancement is very modest (e.g. a doubling of butane viscosity with 2% PDMS at 7MPa and 25°C), making field application of PDMS unlikely. A dilute concentration of a drag-reducing agent (DRA) poly-α-olefin that has an average molecular weight greater than 2.0 107 is more promising as a potential thickener for liquid butane, liquid propane and liquid or supercritical ethane. The DRA polymer, which is introduced as an extremely viscous 1% or 2% solution in hexane, is soluble in butane and propane at 25–60°C and concentrations up to at least 0.5wt% at pressures slightly above the vapor pressure of butane or propane. The DRA polymer is much more difficult to dissolve in ethane, however, requiring pressures of more than 20MPa. The DRA polymer is especially effective for thickening butane (e.g. a 4.8-fold viscosity increase at 25°C, 55.16MPa and 0.2wt% DRA). The DRA is less effective for increasing propane viscosity (e.g. a 2.3-fold viscosity increase at the same conditions), and even less effective for thickening ethane. In general, viscosity enhancement increases with decreasing temperature, increasing pressure, and an increase in the carbon number of the light alkane, which are reflective of increased NGL solvent strength at low temperature and high pressure. Practical application of DRA during EOR may be hindered, however, by the relatively high concentration (~5000ppm) of DRA polymer required for order-of-magnitude viscosity increases, very high pressure requirements for DRA dissolution if the ethane content of the NGL is high, and the large amount of hexane that would have to be introduced if the DRA polymer if it is introduced as a solution in hexane.

Numerical studies on the effects of various complicated barrier configurations on sweep efficiency in surfactant/polymer flooding

The effects of impermeable shale barriers on the performances of surfactant flooding and surfactant-polymer (SP) flooding are studied through numerical simulation by CMG (STARS) software. The barriers are assumed to exist in various configurations in a quarter five-spot pattern either by changing the location and size of a single barrier or by altering the number of barriers existing between two wells. The results show that small-type barriers exhibit positive effect on the enhanced oil recovery (EOR) process in surfactant flooding. In contrast, oil production is affected adversely in SP flooding when barriers are present in any types of configuration.

The Performance of Surfactant-Polymer Flooding in Horizontal Wells Consisting of Multilayers in a Reservoir System

Surfactant-polymer (SP) flooding has been demonstrated to be an effective method to recover oil in the enhanced oil recovery (EOR) stage when water flooding is no longer relevant. Theoretically, adding surfactant causes the reduction of the interfacial tension between oil and water in pores, therefore reducing the residual oil saturation, whereas the sweep efficiency will be significantly improved by the polymer injection as a result of proper mobility control. With regard to the well patterns, water flooding has demonstrated a high productivity in horizontal wells. Recently, other EOR processes have been increasingly applied to the horizontal wells in various well patterns. In this study, the efficiency of SP flooding applied to horizontal wells in various well configurations is investigated in order to select the best EOR performance in terms of either a technical or economical point of view. Furthermore, the reservoir is assumed to be anisotropic with four different layers that have same porosity but different permeability between each layer. The study figures out that, the utilization of a horizontal injector and producer always gives a higher oil production in comparison with the reference case of a conventional vertical injector and producer; however, the best EOR performances that demonstrate the higher oil recovery and lower fluid injected volume than those of the reference case are achieved when the production well is located in bottom layers and parallel with the injection well at a distance. While the location of producer decides oil productivity, the location of injector yet affects the uniformity of fluids propagation in the reservoir. A predefined feasibility factor is also taken into consideration in order to reject the infeasible cases that might give a high oil production but require a higher injected volume than the reference case. This factor is used as an economic parameter to evaluate the success of the EOR performance. The simulation is carried out in a quarter five-spot pattern reservoir with the support of the Computer Modeling Group (CMG) simulator. Understanding the predominant EOR performance of SP flooding in horizontal wells will help to select the best plan to obtain the highest oil recovery when considering economic issues.

Correlations of viscous fingering in heavy oil waterflooding

In order to include viscous instability in modeling heavy oil waterflooding, it is essential to predict the nature of viscous instability. It is still unclear as to whether previous findings of viscous fingering in immiscible displacements in the presence of high single-phase permeabilities and linear displacement schemes are valid in displacement schemes similar to oil-field patterns (e.g., five-spot) and what the effect of dispersion (caused by varying velocity profiles) is on viscous fingering. To overcome the limitations of previous studies of viscous fingering in immiscible displacements, we conduct experiments in low-permeability, one-quarter five-spot patterns. The correlation of experimentally measured oil recoveries, pressure drops, saturation profiles, viscous fingers length and width, dynamic population of fingers, and rate of growth of fingers population with time and front position are discussed. Study of viscous fingering patterns in heavy oil waterflooding conducted in this work provides new insights into the onset of fingering and fingers development.

Solvent-Enhanced Steamdrive: Experiences From the First Field Pilot

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 175414, “Solvent-Enhanced Steamdrive: Experiences From the First Field Pilot in Canada,” by M.L. Verlaan, SPE, and R. Hedden, SPE, Shell Canada; and O. Castellanos Díaz, V. Lastovka, SPE, and C.A. Giraldo Sierra, Shell Chemicals Americas, prepared for the 2015 SPE Kuwait Oil and Gas Show, Mishref, Kuwait, 11–14 October. The paper has not been peer reviewed. In recent years, the addition of a hydrocarbon condensate to steam operations in heavy-oil and bitumen reservoirs has emerged as potential technology to improve not only oil recovery but also energy efficiency. The idea of solvent addition to a steamdrive process has been extended and applied for the first time in the Peace River area in Canada. There, evidence was obtained of oil uplift in the patterns where solvent was injected. However, piloting this new technology in a brownfield had many challenges, especially when evaluating its main economic factors: production increase and solvent recovery. Introduction Vertical-well steamdrive (VSD) is the selected process to recover bitumen from the Peace River Bluesky formation. Solvent coinjection has been identified as an economical method to improve the efficiency of this process. In an early phase of the steamdrive, a slug of hydrocarbon condensate (diluent) is coinjected with the steam. The solvent condenses at the cold steam/bitumen interface to form a solvent bank. This bank has the potential to accelerate bitumen production by viscosity reduction and to improve ultimate recovery. The efficiency of the diluent coinjection in a steamdrive process is expected to be lower than that of liquid addition to steam for enhanced recovery; however, the solvent recovery factors are expected to be much higher. The solvent recovery, therefore, is a key factor in the economic viability of the process. The main objectives of the pilot were to obtain a positive response in bitumen production and accurate quantification of the diluent recovery. An accurate assessment of the bitumen-production increase was not expected because of the small size of the pilot and lack of control patterns; hence, the injection slug size and concentration were designed to obtain a significant and measurable bitumen response. Pilot Design The Peace River lease in Alberta, Canada, has been subject to many well-and recovery-technology trials in the last 30 years. One of the technologies tried is cyclic steam stimulation (CSS) with multilateral horizontal wells. Pad 19 has been developed with so-called “soak radial wells”—four horizontal laterals in a cross pattern. Over a 9-year time frame, bitumen has been produced in seven to eight CSS cycles. With a recovery of less than 20% from the initial design, a part of the pad has been converted to a pattern steamdrive to increase recovery to more than 50%. Vertical injectors and producers are drilled to complete the 5-acre inverted- fivespot patterns. Vertical producers are perforated over almost the complete interval, while steam injectors have been completed with five limited-entry perforations (LEPs) to distribute the steam evenly over the entire reservoir interval.

Visualization of Carbon Dioxide Enhanced Oil Recovery by Diffusion in Fractured Chalk

Summary This work demonstrates that diffusion may be a viable oil-recovery mechanism in fractured reservoirs during injection of carbon dioxide (CO2) for enhanced oil recovery, depending on the CO2 distribution within the fracture network and distance between fractures. High oil recovery was observed during miscible, supercritical CO2 injection (RF = 86% original oil in place) in the laboratory with a fractured chalk core plug with a large permeability contrast. Dynamic 3D fluid saturations from computed-tomography (CT) imaging made it possible to study the local oil displacement in the vicinity of the fracture, and to calculate an effective diffusion coefficient with analytical methods. The obtained diffusion coefficient varies between 0.83 and 1.2 ×10−9m2/s, depending on the method used for calculation. A numerical sensitivity analysis, with a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO2 injection declined exponentially with increasing diffusion lengths from the CO2-filled fracture and oil-filled matrix. In a numerical upscaling effort, with the experimentally achieved diffusion coefficient, oil-recovery rates and local flow were studied in an inverted five-spot pattern in a heavily fractured carbonate reservoir.

Screening and optimisation of water/foam/gas injection EOR scenarios in a fractured reservoir

Primary sweep efficiency in carbonate reservoirs is low due to the low contribution of the matrix in production. Also, due to unfavourable mobility ratio, secondary recovery is not also effective. Hence, design and application of an effective enhanced oil recovery method is essential to improve recovery. Different methods such as water injection, gas injection, chemical injection, thermal, and a combination of these methods such as water alternating gas (WAG), simultaneous WAG (SWAG), selective simultaneous WAG (SSWAG), foam injection, and foam-assisted WAG (FAWAG) are applied to improve the recovery efficiency in naturally fractured reservoirs. In this paper, selection of the best EOR method and well pattern for a naturally fractured reservoir is studied to reach the highest net present value (NPV) and field oil recovery efficiency (FOE). Results showed that the FAWAG process in a five-spot well pattern with 22.7% oil recovery efficiency is the best technical and economical method.

Effect of polymer concentration on the polymer adsorption-induced permeability reduction in low permeability reservoirs

This study presented the effect of polymer adsorption-induced permeability reduction on oil recovery, particularly in low permeability system. The polymer injecting experiments were conducted in a quarter of five-spot pattern with concentrations generally applied. Especially, by using the field oriented two-dimensional sandstone, we attempted to analyze the combined effect of polymer retention for concentration and high velocity near injection on oil recovery.Particularly in low permeable sandstone, oil recovery was not proportionally enhanced with increase in polymer concentration, rather decreased at concentrations above 1,000 ppm in this experiment. This could be understood by polymer adsorption phenomena corresponding to concentrations. The polymer adsorption layer formed at high concentration clogged effective pore radius by up to 59.8%, compared to clean sandstone and the permeability greatly decreased from 56 to 1.5 mD, resulting in rather decreased oil recovery. For this reason, there should be an optimum concentration for maximizing the oil recovery. It was also confirmed by shear rate analysis. At high concentration, the shear rate near injection where has the highest velocity was greater than critical rate. This means that polymer molecules adsorbed to mono-layer of adsorption by hydraulic force, and the adsorption became additionally thicker and hindered the oil flow.

Effects of Directional Permeability Anisotropy on Sweep Efficiency for Five-Spot and Nine-Spot Pattern Flood

Water flooding is the dominant fluid injection technique and is frequently applied worldwide secondary recovery process, which involves water injection in the oil formation under high pressure through an injection well to enhance oil recovery of the well(s) of interest. In order to plan implement successful water flooding optimum number of wells and location must be selected. This involves successful and judicious selection of water flood pattern to increase the reserves. This study emphasizes on important and effect of water flood pattern on oil recovery. This paper will also address the effect of the directional permeability on Cartesian and uniform grid. The patterns studied were fivespot and nine-spot pattern and by ignoring the gravity and capillary pressure the designed model will calculate the pressure and the water saturation for all nodes in five and nine spots scheme. The work shows that both pattern schemes produce almost the same tertiary oil under identical reservoir conditions. The nine point’s scheme showed smooth pressure and water distribution compared to five point’s scheme. A breakthrough time was earlier by 40-50 days for the nine spot patterns as compared to five spots pattern.

The Research of Gas Flooding of Horizontal Well with SRV in Tight Oil Reservoir

The characteristics of tight oil reservoir are low porosity and ultra-low permeability, thus stimulated reservoir volume (SRV) should be conducted whether applying the mode of vertical wells or horizontal wells production. Tight oil reservoir is mostly developed by natural depletion or water flooding recently, but the problems are existed, including low recovery factor with natural depletion and the difficulty of water injection. To further improve the development effect of tight oil reservoir, CO2 flooding is proposed. Based on changing tight oil reservoir in Ordos Basin, an oil sample of typical block is selected. The PVT experiments are conducted. The compositional numerical model of five-spot pattern is established with a horizontal well in the middle and 4 vertical wells on the edge. Based on the model, several CO2 flooding scenarios of horizontal well with different completion measures are studied. Furthermore, parameters such as the formation pressure, production rate, shut-in gas-oil ratio and total gas injection volume are optimized. The results of this study show that the recovery factor of horizontal well with SRV is higher than those of horizontal well and conventional fractured horizontal well. The study gives new ideas of CO2 flooding with volume fractured horizontal well for the Ordos Basin tight oil reservoir. It can be helpful for rapid and effective development of tight oil reservoirs in Ordos Basin.