Effects Of Gravity Segregation Research Articles

Gas condensate well productivity in fractured vuggy carbonate reservoirs: A numerical modeling study

The spatial distribution of fractures and cavities may generate important impact on the fluid flow behavior in fractured vuggy carbonate reservoirs. However, the recovery mechanism of gas condensate wells is not well understood due to the lack of effective reservoir simulation methods that coupled porous-medium and free flows occurring in fractured vuggy carbonate reservoirs. In this work, a novel compositional reservoir model is developed for modeling the production dynamics of gas-condensate well in complex fractured vuggy reservoirs. The compositional multiphase fluid flow through rock matrix and fractures is assumed to follow Darcy's law, while the free flow in cavities is modeled based on the assumptions of instantaneous thermodynamic equilibrium and phase segregation controlled by gravity. An advanced numerical calculation method combining finite volume method (FVM) and embedded discrete fracture-vug model (EDFVM) is developed to efficiently solve the multi-component multiphase flow problem. Case studies are conducted to investigate the gas-condensate flow behavior and well production performance under various configurations of fracture-cavity patterns. Two scenarios are considered by placing the production well at the top and bottom of the models, which aim to mimic different locations of directional well target. The results indicate that when cavities are present, condensate oil accumulates mainly beneath the cavities due to the effect of gravity segregation. Thus, more condensate oil may be produced with depletion at the bottom of the reservoir. However, condensate oil distributes surrounding the production well when cavities are absent, and the production performance of gas-condensate well is less affected by depletion location. Furthermore, the cumulative condensate oil and gas production are higher when cavities are present because of the continuous supplement of condensate gas by cavities. Our research findings have important implication for the design of directional well planning in the fractured vuggy gas condensate reservoirs.

Using a well-to-well interplay during the CO2 huff-n-puff process for enhanced oil recovery in an inclined oil reservoir: Experiments, simulations, and pilot tests

A well-to-well interplay of CO2 huff-n-puff is proposed as a novel gas injection strategy for displacing interwell-remaining oil in a well pair in an inclined oil reservoir. The well-to-well interplay mechanisms for enhanced oil recovery (EOR) are first studied in the laboratory using a three-dimensional (3D) physical model. Different CO2 injection schemes are designed according to different well locations, and the production performance including oil, water, and gas rates is used for the EOR evaluation. A sensitivity analysis of the well-to-well interplay is then studied using a numerical model, and geological, developmental and fluidic factors are considered in the simulations. The experimental results show that, when CO2 is injected into a lower well, a higher well always benefits with an oil increment. Under the effects of gravity segregation and edge-water driving, the injected CO2 at the lower position can move upward to a higher position, where a large proportion of crude oil remains between wells after natural edge-water flooding. Oil recovery from the well-to-well interplay is 2.30% higher than conventional CO2 huff-n-puff in the laboratory. Numerical results show that CO2 injection mass, stratigraphic dip, horizontal permeability, and interwell spacing are the factors that most influence the well-to-well interplay; an application criterion for the well-to-well interplay is then proposed based on the simulations. Pilot tests using the well-to-well interplay of CO2 huff-n-puff have been widely applied in C2-1 Block, Jidong Oilfield, China, since 2010. A total of 2.27 × 104 m3 crude oil was recovered to the end of 2018, and the oil/CO2 exchange ratio was as high as 3.92. The well-to-well interplay not only effectively extracted the interwell-remaining oil but also achieved higher CO2 utilization efficiency. The findings of this study can lead to a better understanding of the EOR mechanisms used in the well-to-well interplay during the CO2 huff-n-puff process in an inclined oil reservoir.

Application of New Compositional Simulation Approach to Model Gravity Segregation In Volatile Oil Reservoirs

In this paper, we investigate the recovery performance of gas injection from volatile oilreservoirs. Cross-sectional reservoir studies for investigating the gravity segregation duringdepletion and gas cycling in volatile oil reservoirs is discussed. Furthermore the effectsof vertical permeability on gravity segregation in a homogeneous and horizontal reservoirsare investigated.A new efficient compositional simulation approach was used in this study to investigatethe influence of gravity segregation and their magnitude in the case of lean gas injectioninto a volatile oil reservoir. The new compositional simulation approach was validatedthrough analytical and numerical methods, and it is unconditionally stable and as stableas fully compositional model.The results show that an increase in vertical to horizontal permeability ratios results inan increase in the effect of gravity segregation and yield early gas breakthrough. On theother hand, the smaller the permeability ratios (vertical to horizontal), better are the recoveriesdue to resulting even layer sweeps. Gravity forces have a considerable effect onvolatile oil recovery via gas injection and the need for determining not only the fluidcharacteristics but also the reservoir heterogeneities was significant.

Modeling Gravity Segregation In Stratified And Dipping Reservoir Of Volatile Oil

In this paper, we investigate gravity segregation in stratified and dipping reservoir of volatile oil under gas injection. A new efficient compositional simulation approach was used in this study to investigate the influence of gravity segregation and their magnitude in the case of gas injection into a volatile oil reservoir. The results show that in stratified and dipping reservoirs where the permeability decreases with depth, smaller the vertical to horizontal permeability ratio, lesser is the effect of gravity segregation, better is the sweep efficiency and hence better is the recovery. In the case of increasing permeability with depth in stratified dipping reservoirs, an up-dip gas injection into a volatile oil reservoir was found to be a favourable condition in term of recovery. Gravity forces have a considerable effect on volatile oil recovery via gas injection and the need for determining not only the fluid characteristics but also the reservoir heterogeneities was significant

Preparation and rheological Evaluation of a thixotropic polymer gel for water shutoff in fractured tight reservoirs

In this study, a thixotropic and high-strength gel system (THSG) is developed, which is experimentally proven to be feasible for conformance control in fractured reservoirs. The THSG is based on in-situ polymerization of the acrylamide monomer, incorporating a weak gel system. It is found that the superior rheological properties of THSG are beneficial for injection and placement of gelant into the fractures. The viscosity of THSG at varying shear rates can be well fit by the Carreau–Yasuda model, and its shear thinning behavior contributes to low injection pressure during the gelant injection. Moreover, this THSG system exhibits much better thixotropy than the traditional Cr(Ⅲ)-acetate-HPAM gel system (HPAM/Cr(Ⅲ) gel), which would enable the THSG an easier access to the small apertures. It is also found that the injection pressure is greatly increased with decreasing of the diameter of aperture during injection of the HPAM/Cr(Ⅲ) gel, while little effect of the aperture size on injection pressure was observed during THSG injection. Additionally, the yield stress of the thixotropic gelant is noticeably high, which would greatly mitigate the adverse effect of gravity segregation in fractures during well shut-off. This would be also beneficial for plugging the whole fractures. To better understand the properties of THSG, the gelation performance, the microstructure of the gel and the blocking ability of gel in the tubes were investigated. The results show that the clay particles strengthened gel exhibits a large storage modulus and excellent thermal stability. Scanning electron microscopy (SEM) results show that the clay particles were readily distributed on the polymer chains, and the clay particles could facilitate the gel to form a firm and uniform network. Consequently, the clay particles strengthened THSG gels have relatively high rupture pressure, which would be exceedingly favorable for efficient gel treatments in fractured reservoirs. • Rheology behaviors of the THSG have been studied. • The flow curve of the THEG can be well described by the Carreau–Yasuda model. • The THSG has a typical thixotropic behavior, which can effectively plug the entire fractures. • The injection pressure of the THSG is almost irrelevant to the apertures.

Effect of gravity segregation on CO2 flooding under various pressure conditions: Application to CO2 sequestration and oil production

This research evaluates the effect of gravity segregation on CO2 sequestration and oil production during CO2 flooding under immiscible, near-miscible, and miscible conditions. The core experiment results show that CO2 flooding recovery was seriously affected by gravity under immiscible conditions, while under miscible conditions, this influence was not apparent. Visual experiments show when immiscible, gravity restricts the oil and gas front’s stability, and different gas injection strategies have evident differences in the swept region; when miscible, gravity has almost no effect on the swept region. These results indicate that when CO2 immiscible flooding is implemented, the reservoir thickness affects the choice of gas injection direction. However, for miscible flooding, the reservoir thickness and gas injection direction are not essential for developing CO2 flooding. In immiscible conditions, gas injection velocity greatly restricts the CO2 gravity flooding recovery; in miscible conditions, the velocity is no longer the main influencing index of CO2 gravity flooding recovery. For CO2 sequestration, gravity segregation is conducive to increasing CO2 sequestration potential. As the pressure increases, the influence of gravity on CO2 sequestration weakens. Regardless of whether there is gravity effect, the best oil recovery and gas sequestration potential of CO2 flooding is obtained under miscible conditions.

Geomechanical Simulation of Partially Propped Fracture Closure and Its Implication for Water Flowback and Gas Production

Summary Uneven proppant distribution is often encountered in hydraulic fracturing. Despite propped and unpropped fractures exhibiting different closure behavior during shut-in and early-flowback periods as a result of changes in effective stress, modeling of the geometry and closure behavior of a partially propped fracture is rarely performed. Numerical simulation is used in this study to simulate the closure behavior of a partially propped fracture and to examine its effects on water flowback and gas production. Explicit finite-difference geomechanical simulation is used to simulate the change in effective stress and the corresponding closure geometry of a partially propped fracture. Parameters including rock strength, in-situ stress condition, proppant compaction, and propped-fracture height and aperture are considered to understand their effects on the fracture-closure geometry. This partially propped fracture is then represented explicitly in the computational domain in a flow simulation to model fluid flow during the shut-in and flowback periods. Fracture volume and fracture conductivity are adjusted as a function of effective stress to represent the fracture-closure process. The effect of coupling of partially propped fracture closure and multiphase flow on water recovery and gas production is investigated. Implications of ignoring the physical process of fracture closure and complex partially propped fracture geometry are examined. Geomechanical-simulation results reveal the potential formation of a residual opening above the proppant pack in a partially propped fracture. Three distinct parts are identified within a partially propped fracture: a propped region, an unpropped region, and a residual opening (arch). The size of the residual opening is most sensitive to the initial fracture aperture. Stress concentrations occur at the top of the proppant pack and lead to potential proppant crushing or embedment. In addition to water uptake into the matrix because of forced (large pressure differential across the matrix/fracture interface) and spontaneous (high capillary pressure in the matrix) imbibition, fracture closure during the shut-in and flowback periods could displace more water into the nearby matrix and reduce the final water recovery. The residual opening would exaggerate the effects of gravity segregation and hamper water recovery by providing a highly conductive flow path to gas flow, such that the water would accumulate near the bottom of the fracture. The implication is that more-aggressive drawdown should be implemented to recover the fracturing fluid. This study offers a quantitative analysis of the geometry of a partially propped fracture and highlights its effects on water flowback and gas production. The existence of the residual opening, which is commonly ignored in most analysis, would indeed play a crucial role in the subsequent well performance and in-situ fluid distribution. A number of insights pertinent to practical fracture design and operational strategy are discussed.

Reactive transport modelling of hydrothermal dolomitisation using the CSMP++GEM coupled code: Effects of temperature and geological heterogeneity

Reactive transport simulations using our CSMP++GEM coupled code were applied to study the major controls on replacement dolomitisation and the development of dolomite geobodies in a hydrothermal setting. A series of 2D simulations show how elevated temperature and reactive surface area increase the rate of dolomitisation, and result in a dolomite replacement front that is both sharper and inclined at a higher angle from vertical. This inclination, an effect of gravity segregation, is apparent in thick homogeneous units, but in layered systems the lithological contrast determines the shape of the dolomite front. The increase in permeability resulting from porosity generation upon replacement of calcite by dolomite has a major effect on accelerating the overall progress of dolomitisation. In contrast, the changes in fluid density due to chemical reactions and the pressure dependence of thermodynamic data have a minor influence under simulated conditions. Primary dolomite forms slowly after complete replacement of host calcite, leading to porosity decrease, and is only locally important around the source of the hydrothermal fluid.For a simple layered system, our model results are in excellent agreement with those obtained using TOUGHREACT code. They do, however, show the advantage of unstructured triangular over structured rectangular meshes for resolving complex curved/inclined front shapes. Such meshes also offer benefits in simulating fault-controlled hydrothermal dolomitisation.Our simulations predict dolomite geobodies comparable in scale and morphology to natural examples documented at outcrops, and underline the importance of understanding the permeability structure within and around the fault zone.

Effect of gravity segregation on CO2 sequestration and oil production during CO2 flooding

In this study, we attempted to analyze CO2 sequestration and oil production in the environment of gravity segregation, and ultimately making a relationship between them during the CO2 flooding. In order to utilize the depleted oil field after finishing the CO2 flooding as CO2 storage, quantitative characteristics of CO2 storage efficiency to be possible in that oil field should be understood for preventing a leak through fractures generated by high-pressured CO2 of free gas state prior to the injection of CO2. As an experimental system, we designed a two dimensional CO2 flooding apparatus equipped with sandstone plate. The apparatus had dip angles of 0° (horizontal system) and 90° (vertical system) to simulate gravity segregation condition. Experimental results for the vertical system showed that oil production was heavily influenced by gravitational effects for immiscible condition. This situation is analogous to thick reservoirs in which gravity dominates over viscous forces. However, for near-miscible condition, the gravity override phenomenon was not significant, and these results suggest that reservoir thickness should not be a criterion when using CO2 flooding. CO2 storage efficiency for near-miscible system was found to be much better than that for immiscible system regardless of the gravitational effect. For designing the CO2 EOR scheme in terms of relationship between CO2 storage and oil production, particularly in the case of high permeable homogeneous sandstone, we found out that the trapped CO2 as free gas state and oil recovery during the CO2 flooding were monotonically decreased without critical value of inflection point corresponding to CO2 injection rate increase.

Inflow Performance Relationships Under Gravity Segregation for Solution Gas-Drive Reservoirs

This paper analyzes the influence of gravity segregation effects on inflow performance relationship (IPR) curves, with both totally and partially penetrated vertical wells. Using synthetic responses from a finite difference simulator, the effects of different parameters, such as vertical to radial permeability ratio, production mode, position of productive interval, oil rate, and mechanical skin, on the shape of IPR curves are documented. It is shown that greater flow potentials are obtained when the ratio of gravity to viscous forces increases. It is shown that for the case of partially penetrated wells, the IPR curve generated at constant bottomhole pressure does not coincide with the IPR generated at constant oil rate. Also, the presence of gravity segregation affects the values of absolute open flow potential, obtaining big differences with the corresponding values when gravitational effects are ignored. The values of the exponent n of Fetkovich IPR and the coefficients of the quadratic equation proposed by Jones et al. are functions not only of time but also of production rate, position of productive interval, and other parameters. The consequence of the above results is that the interpretation of IPR curves is affected by the presence of gravitational effects and therefore the use of traditional methods, such as those of Vogel , Fetkovich, or Jones et al., is restricted to the specific conditions considered by these authors.

Gravity segregation during miscible displacement—re-investigation and re-interpretation

When the liquid residing in a horizontal bed of porous material is displaced by another liquid of different density, the resulting hydrodynamic dispersion is modified by the formation of a tongue of denser liquid undershooting the less dense liquid, a phenomenon known as gravity segregation. An earlier account of gravity segregation contained a substantial error (that of an incorrect frame of reference for flow) and several printing mistakes. In this paper we (i) correct these errors, (ii) extend the analysis to describe the course of breakthrough in beds of rectangular and circular cross-sections, (iii) re-interpret the existing experimental evidence, and (iv) present new experimental results on the vertical and horizontal transport of ionic solutions of different concentrations and densities through inert and reactive porous materials, ballotini, and sepiolite, respectively. The behaviour of immiscible liquids is predicted by the non-dimensional gravity segregation number, β, segregation becoming more extreme as β increases. With miscible liquids, however, breakthrough starts later and ends earlier then predicted for immiscible liquids, mixing by hydrodynamic dispersion moderating the effect of segregation. Breakthrough curves are well fitted by CXTFIT 2.0; apparent coefficients of hydrodynamic dispersion vary much less with pore-water velocity in horizontal than in vertical flow, but retardation factors are not influenced by orientation. Although a formal analysis of the combined effect of gravity segregation and hydrodynamic dispersion was not possible, the statistically significant inverse relation between β and column Peclet number was explained qualitatively. Gravity segregation occurs during the intrusion of saline groundwater into coastal aquifers. The simple theory for immiscible displacement overestimates the actual intrusion that occurs with miscible liquids and so provides an effective safety margin.

Coreflood Studies of Tertiary CO2 Flood in Naturally Fractured Midale Formation in Southeast Saskatchewan

Abstract The distinctive geology of the Weyburn and Midale reservoirs has important implications for the design of a CO2 injection process for these fields. They are contained within two distinct zones of the Mississippian Carbonate formation; the tight, high-porosity Marly zone sits on top of the low-porosity Vuggy zone. The latter zone has a higher permeability, and is more extensively fractured vertically, than the Marly zone. These geological features result in a relatively unswept Marly zone after waterflooding. The Marly/Vuggy sequence presents an opportunity for a CO2 flood to take advantage of gravity segregation to recover the large remaining oil target in the Marly zone. A series of coreflood tests were conducted to simulate tertiary CO2 injection in the Marly/Vuggy zones in the Weyburn and Midale reservoirs. Berea cores with different permeabilities were split lengthwise. The halved segments of the core were butted together to represent the Marly and Vuggy zones. Water (in waterflood mode) and CO2 (in tertiary CO2 flood mode) were injected into the bottom high-permeability section of the dualpermeability core. The coreflood results showed that, in the tertiary CO2 flood, CO2 could migrate to and recover the oil from the top low-permeability zone which was poorly swept by the waterflood. Also, the effects on tertiary oil recovery of operating pressure, injection rate, and permeability contrast could be significant. Introduction The Weyburn and Midale reservoirs in southeast Saskatchewan hold light and medium gravity oil in fractured, low permeability Midale Beds. These reservoirs are contained within two distinct zones of the Mississippian Carbonate formation: the tight, highporosity Marly zone sits on top of the low-porosity Vuggy zone. The latter zone has a higher permeability, and is more extensively fractured vertically than the Marly zone. These geological features result in a relatively unswept Marly zone after waterflooding. It is believed that the distinctive geology of these reservoirs has important implications for the design of a CO2 injection process for these fields, i.e., the Marly-Vuggy arrangement of the reservoir offers potential to utilize gravity segregation effects to enhance oil recovery. Numerical analyses(1, 2) of tertiary CO2 injection in these naturally fractured reservoirs showed that CO2 injected into the lower, more permeable Vuggy zone can contact and mobilise a large amount of oil in the Marly, which has remained relatively unaccessed by waterflooding. A coreflood program was designed at Saskatchewan Research Council (SRC) to address the CO2 injection process in Weyburn reservoir and comparable fields. Laboratory core displacement tests were conducted with a dual permeability split Berea core representing the Marly and Vuggy zones of a reservoir. Some preliminary results reported in a previous paper(3) showed that CO2 injected into the Vuggy zone could rise to the upper Marly zone, and that the potential to recover incremental oil by a tertiary CO2 slug flood is high. After the technique of butting the core halves was improved, the several additional tertiary CO2 coreflood tests reported here were performed with Weyburn reservoir fluid at 63 ° C (reservoir temperature) to confirm the previous finding.

A New Combustion Process Utilizing Horizontal Wells And Gravity Drainage

Abstract The Combustion Override Split-production Horizontal-well (COSH) process has been conceived to combine the high recovery potential of gravity drainage with the energy efficiency of combustion processes while minimizing problems associated with combustion operations. COSH should be less sensitive to oil composition and combustion kinetics and it has minimal water supply and disposal requirements. The mechanisms for the COSH process have been identified within the limitations of numerical simulation. A simulation study indicates that the COSH process has technical performance approaching that for the highly rated steam-assisted gravity drainage (SAGD) process, and has much lower energy costs. Introduction In-situ combustion has been studied and piloted for several decades because it has the potential of the highest energy efficiency and lowest production cost among thermal processes(1) Unfortunately, overall field experience has been disappointing because of numerous problems such as slow production response difficulty in sustaining combustion, early oxygen breakthrough, severe sanding, gas locking of down-hole pumps, corrosion, and scaling. The literature on combustion studies relates primarily to frontal displacement of the combustion zone. This involves linear or radial areal displacement from vertical injection wells to vertical production wells with the pay-zone visualized as being divided into successive zones including a combustion zone followed by a condensing zone and an oil bank which is displaced ahead of the combustion front. Many elegant and sophisticated studies have been conducted on the dynamics of the combustion process for linear displacement, particularly with combustion tubes(2). Unfortunately, it is very difficult to model in the laboratory the three-dimensional effects of gravity segregation of fluids and poor vertical and horizontal sweep efficiency which are at the heart of many of the problems in field combustion projects. It is also difficult to analyze the process mechanisms in combustion field projects which have been reported to increase oil production. In particular, for field projects it is difficult to determine the relative importance of thermal effects, gravity drainage (particularly in dipping reservoirs) and complex three-phase relative permeability effects caused by the large volumes of gas and water used. This paper will present a new approach to take advantage of the theoretical efficiency of combustion by combining the best features of successful steam pilots that the Alberta Oil Sand Technology and Research Authority (AOSTRA) has participated in while minimizing the negative features responsible for problems reported in earlier field combustion projects. COSH Process The main features in the Combustion Override Split-production Horizontal-well (COSH) process(3) are described as follows, with reference to Figures I and 2:Gas containing oxygen is injected via rows of vertical injection wells. The gas may be air, oxygen or recycled gas with oxygen added. The gas is generally injected in the upper part of the pay-zone. Maintaining continuous gas injection into the reservoir and cold water circulation within the wells will prevent combustion damage. The vertical wells can also serve to define the geology and locate the base of the pay-zone accurately prior to drilling the horizontal production well and they could be used to monitor temperature profiles in the lower part of the gas chamber with cemented-in thermocouples.

3D Simulation of Viscous Fingering and WAG Schemes

Summary Water-alternating-gas (WAG) injection has been suggested as a way to reduce viscous-fingering. This paper presents 3D simulations to assess the combined effects of gravity segregation in the vertical plane and areal viscous fingering for miscible displacements with substantial viscous fingering and for WAG injection. The simulations illustrate variations in recovery with WAG ratio and viscous-to-gravity ratio. A procedure to recalibrate the Todd and Longstaff parameter for WAG schemes in which buoyancy forces have little effect is described. Use of this recalibration provided excellent agreement with results from detailed simulation. Where gravity is important, recalibration of the parameter is required; examples of recalibration coarse-grid calculations are presented.

Laboratory Evaluation Of Crosslinked Polymer And Alkaline-Polymer-Surfactant Flood

Abstract This paper discusses the feasibility of using cross-linked polymer technology and alkaline-polymer-surfactant technology to improve oil recovery in the Grand Forks Lower Mannville "D" pool. The Grand Forks "D" pool is a good quality channel sand withan original oil-in-place of 15.9 × 106 m3 (100 × 106 STB). The rock has a porosity of 25% and the permeability ranges from 1000 md to 10000 md with an average of 3000 md. The reservoir crude has a viscosity of 11 MPa •S at the reservoir temperature of 31 °C (88 °F) and a stock tank gravity of 898.4 kg/m3. Primary and Water-flood oil production has produced 25.5% of the original oil-in-place as of January 1986. Previous model studies and historical pool performance indicated that up to 60% of original oil-in-place could be left in the reservoir after water-flooding due to gravity effects and high vertical permeability. A scheme of combining cross-linked polymer technology and alkaline-polymer-surfactant technology has been developed to optimize the ultimate oil recovery. The application of cross/inking technology was investigated using cationic and anionic polymers with various cross-linking agents through linear coreflood and viscosity monitoring studies. The application of alkaline-polymer-surfactant technology was studied through interfacial tension, fluid compatibility, phase behavior, chemical adsorption, rock dissolution, and coreflood studies. Core flood studies included injectivity as well as oil recovery studies. The results of the laboratory studies indicate that the alkaline-polymer system can recover incremental oil over water-flooding of approximately 30% of original oil-in-place. With an addition of 0.1 % by weight of surfactant, up to 47% of original oil-in-place can be recovered. No injectivity and fluid incompatibility problems were detected. The test results also indicate that the residual resistance factor can be increased significantly by cross-linking. This should help improve the vertical sweep efficiency by diverting the subsequent injection fluids into the unswept zones. It was concluded that a chemical flood is technically feasible for the subject pool. Introduction The Grand Forks Lower Mannville "D" pool is located in southeastern Alberta (Fig. 1). Figure 2 shows the well configuration of the pool. The pool, which is a Lower Cretaceous channel sand, is one of the most productive oil reservoirs in the area. The original oil-in-place is estimated to be 15.9 × 106m3. Table 1 lists some of the reservoir rock and fluid properties. The reservoir has yielded more than 3.97 million m3 of oil from the Lower Mannville sand since its discovery in 1968. The field has been water flooded for more than nine years and water-cut has been increasing steadily since then. The pool now has 34 producers and four water injectors with a total injection rate of 3100 m3/d (19 500 bbl/d). Current oil production rate is approximately 650 m3/d (41 00 bbl/d) with an average water-cut of 80%. A previous water flood simulation stud y(1) and recent production logs indicated that there is a substantial volume of movable oil still in place. The study also showed that the existing waterflood has a good sweep efficiency in the bottom layers, but poorer in the upper layers due to the effects of gravity segregation, high vertical permeability and reservoir heterogeneity.

Mobility Control In Dynamic Gravity Segregation Flow Systems

Abstract Experiments were carried out in a vertical sand pack to study the effect of gravity segregation on liquid displacement by a miscible liquid, a gas and a combination of the two. The advantages of using a foaming agent during simultaneous gas-liquid injection were also investigated. A gamma-ray attenuation technique was adapted to track the shapes of the moving displacement front and monitor in-situ saturation profiles. The results show that high gas mobility and low density lead to early gas breakthrough and poor sweep efficiency. Even in miscible liquid-liquid displacements a density difference of 0.079 g/cm3 leads to gravity override or under-ride by the displacing liquid. During simultaneous gas-liquid injection the presence of gas increases the severity of the over-ride/under-ride effect and reduces the displacement efficiency of the miscible liquid. In-situ generation of foam is an effective method of controlling the mobility of the gas and improving the conformance of the displacement front. Introduction The purpose of this study was to investigate the characteristics of gravity segregating systems and the use of foaming agents to control the mobility of air and water injected simultaneously into a liquid-saturated porous medium. One of the major factors responsible for poor conformance and low recovery efficiency of several displacement processes(1) is gravity segregation caused by a density difference between displacing and displaced fluids. For example gas-driven processes such as CO2-flooding, alternating water-gas injection, steam injection and in-situ combustion are affected by varying degrees of segregated flow behavior. Several laboratory experiments and numerical studies of fluid flow in porous media have confirmed the importance of a density difference in the occurrence of segregation. Slower rates of segregation were observed in brine-liquid systems than in brine-air systems(2). With miscible liquids the length of the mixed zone was influenced by gravity segregation, and a greater reduction in displacement efficiency was observed when the mixed zone was narrow compared to the height of the experimental model(3). The presence of a broad transition zone tended to nullify the influence of a difference in density(4,5). Gravity segregation is generally thought to be time-dependent and more prevalent in thick heavy oil reservoirs(6). However, some field projects have also shown that segregation can occur instantaneously at the wellbore(7,8), and in static gas-liquid systems only a short time is required for an initially uniformly distributed gas phase to reach a fully segregated state(9). For unit mobility ratios, two miscible fluids will segregate in dynamic flow by the same amount they segregate in a static system(10). Studies in models simulating both linear and five-spot patterns show that volumetric sweep efficiency at breakthrough can be as low as 20% of those with no gravity segregation(11). This reduction in performance is more pronounced with an increase in vertical or horizontal permeability, an increase in density difference, a decrease in production or injection rates, and an increase in mobility ratios(6). Gravity override has been observed in nearly all steam-drive Projects(12). For reasons of convenience, theoretical studies often assume vertical combustion fronts, even though gravity effects are usually evident(12).

The Role of Molecular Diffusion Processes in Tertiary CO2 Flooding

Summary This paper examines the role of molecular diffusion in the mobilization of waterflood residual oil. A numerical model that simulates the swelling of residual oil blobs by CO, diffusion through a blocking water phase is developed. The diffusion times calculated with the model are compared with those calculated in laboratory micromodel and coreflood experiments. The comparison shows that diffusion plays a major role in the mobilization and recovery of waterflood residual oil and that high unit or local displacement efficiencies are achieved when there is sufficient time for diffusion to swell the oil significantly. For the length scales normally associated with laboratory corefloods, diffusion is sufficiently rapid to reduce effectively the adverse effects of bypassing on overall recovery efficiency. This is not so for field floods, where bypassing of oil by injected CO2, may be expected to occur on a much larger scale. Introduction The displacement of oil by CO2 has been the subject of numerous studies, and a considerable volume of experimental data now exists for the process. In these studies, CO2, usually displaces oil from a fully saturated slim tube or test core in a secondary displacement under conditions where phase behavior favors the development of miscibility. For these conditions, recoveries are observed to be high and rate-insensitive, provided that the effects of gravity segregation, viscous fingering, and bypassing are minimized. In direct contrast, for tertiary recovery experiments where CO2, is injected into a previously watered-out test core, recoveries of residual oil are observed to be considerably lower, dependent on both flood rate and core length. and different for water-wet and oil-wet systems. The differences in performance between secondary and tertiary flood experiments are usually explained in terms of the high water saturations present in the tertiary flood experiments and their effect on the microscopic displacement efficiency. As a consequence of the highly unfavorable mobility ratio for the immiscible CO2, water displacement, injected CO2, bypasses considerable volumes of water, leaving high water saturations behind the displacement front in water-wet rock. The water blocks or shields the residual oil from direct contact with the injected CO2. This prevents development of miscibility and results in a considerable reduction in microscopic displacement efficiency. Molecular diffusion of CO2, through the water blocking phase has been suggested as an important mechanism in the mobilization and recovery of the residual oil in water-wet rock. Swelling of the oil phase causes a breakdown of the original capillary equilibrium, resulting in a pore-scale redistribution of the phases. For this process to be fully effective in recovering residual oil, sufficient time must be available for diffusion of CO2, to swell the oil significantly. Recent flow visualization studies in two-dimensional (2D) micromodels qualitatively confirmed the importance of diffusion and oil swelling in tertiary CO2 displacement experiments. These studies have demonstrated clearly that the bulk of the waterflood residual oil is left behind the CO2, displacement front, trapped by water and therefore inaccessible to the flowing CO2, channels. It was further observed that CO, diffusion through the blocking water phase caused isolated oil droplets in water-wet rock to swell. When sufficient time (overnight) was allowed for diffusion, the swelling eventually was enough to break the water barrier that blocked the oil from the flowing CO2, channel and therefore to allow high oil recoveries. Although the available experimental data suggest that diffusion is important in the recovery of waterflood residual oil, the role of diffusion has not yet been quantified. It is therefore not possible to scale the diffusion times and associated nonequilibrium effects responsible for oil recovery in tertiary CO2, floods correctly on the laboratory scale or in the field. The purpose of this paper is to examine the role of molecular diffusion and to determine the time scales necessary for diffusion to be an effective recovery mechanism both in laboratory floods and in the field. An idealized one-dimensional (1D) pore-scale model is developed that simulates CO2 diffusion through a water barrier to a trapped oil phase and the subsequent swelling of the oil phase. The model clearly demonstrates the important role of diffusion in the recovery process. Computed diffusion times are compared with available experimental data both to validate the proposed model and to relate correctly the time scales over which this process is effective both in laboratory corefloods and in the process is effective both in laboratory corefloods and in the field. Model Development The actual mechanism by which waterflood residual oil is mobilized during a tertiary CO2, flood is not yet fully understood. JPT P. 591

Laboratory Evaluation Of Foaming Agents For High-Temperature Applications — I. Measurements Of Foam Stability At Elevated Temperatures And Pressures

Abstract Use of foaming agents holds considerable promise for mitigating the detrimental effects of gravity segregation and viscous fingering in steam drives. Field application of such foams requires careful selection of the foaming agent and judicious design of the injection scheme. In view of the large number of foaming agents commercially available, most of which have never been field tested, the task of selecting the most suitable chemical often requires extensive laboratory evaluations. Measurements of foam stability at steam temperature can be used as the first screening test for selecting foaming agents. This paper presents the results of experimental evaluation of foam stability under conditions of high pressure and elevated temperatures. Foaming agents were tested at different pressures (up to 6.9 MPa) and temperatures up to 200 °C. Foams were generated by injecting nitrogen gas through a gas sparger submerged under the test solution in pressure vessels equipped with glass windows. The drainage of liquid from the foam as well as the rate of decay of the foam volume were then monitored. Results show that the drainage of liquid from foam generally follows first-order kinetics, while the decay of foam volume can be more complex. The half-life for foam volume decay declined dramatically with increasing temperature. At the highest temperature investigated, sulphonates were found to be clearly superior. The relative performance of long-chain alpha olefin sulphonates improved with increasing temperature. This suggests that, at higher temperatures, chain lengths longer than those presently available might be advantageous. Introduction Gravity segregation and viscous fingering are detrimental to the efficiency of many enhanced oil recovery techniques. This is particularly true for recovery of heavy oils with steam drive due to the extremely adverse mobility ratio and the wide difference between densities of steam and reservoir fluids. It has been known for more than 25 years(1) that the efficiency of miscible and immiscible gas drives can be improved by generating a foam which is considerably less mobile compared to the gas. In the case of steam drive, it has been postulated that, if steam is injected as part of the gas phase in a foam, it will partially plug oil-depleted zones and high-permeability channels(2,3). This would divert steam toward undepleted zones and thereby improve oil recovery. Although the steam foam process is conceptually simple, its application on a field scale is not straightforward. It requires careful evaluation of the potential benefits in relation to the cost of the injected chemicals. For best performance, the foaming agent should possess a number of desirable characteristics. These include the capacity to generate a stable foam at steam temperature and high pressure, thermal stability, low adsorption on rock surfaces, compatibility with reservoir fluids, high apparent viscosity of produced foam in porous media, and low cost. Presently, no foaming agent is known to satisfy all these requirements. Laboratory evaluations are therefore required to select the most suitable chemical for a given application. Most of the reported screening studies for identifying promising foams have employed some form of foam stability measurement for initial screening.

Simulation of Sandstone-Matrix Acidizing in Heterogeneous Reservoirs

Summary A numerical simulator wigs developed to predict porosity and permeability changes and the resulting effect on well productivity in permeability changes and the resulting effect on well productivity in sandstones subject to matrix acidizing. While earlier acidizing models are based on homogeneous porous media, here vertical variation in permeability was accounted for by consideration of several noncommunicating zones or layers with different overall permeability-height (Kh) products. Each layer, in turn, may have radial permeability variations and different physical and chemical properties. In this manner, the presence of a damaged physical and chemical properties. In this manner, the presence of a damaged zone can be incorporated by a change in near-wellbore properties. During acidizing, the permeability change at a given vertical location depends on factors that affect acid penetration rate, such as initial acid concentration, mineral composition, temperature, flow rate, and cumulative acid injected at that location. Because the reservoir is vertically heterogeneous, initial distribution of injected acid will be nonuniform, with the majority of the flowing acid tending to enter zones with higher permeabilities. This is unfavorable because the lower-permeability zones permeabilities. This is unfavorable because the lower-permeability zones are of interest in a stimulation treatment. Adding diverting agents to the acid solutions, however, tends to decrease the flow rate of higher-permeability areas and helps to distribute fluid uniformly. The effect of organic resin diverting agents (added continuously) on vertical fluid distribution in a wellbore is also modeled. With our model, the effect of injection rate on acid penetration distance and on diverting-agent efficiency was investigated. Acidization results in a heterogeneous porous medium are compared with results obtained for a vertically homogeneous porous medium. Finally, the design of optimal diverting strategies in matrix stimulation of heterogeneous formations is described. Introduction Sandstone-matrix acidizing is a process aimed at increasing the formation permeability in the vicinity of the wellbore by dissolving some formation material with a mixture of hydrofluoric and hydrochloric acid. Several investigators have developed models of this process that consider flow through the porous media with simultaneous heterogeneous reactions between acid and the solid matrix. These models provide a means for estimating volumes of acid needed for provide a means for estimating volumes of acid needed for desired levels of stimulation, depth of penetration of acid, and the resulting changes in permeability for matrix acidization in homogeneous reservoirs. Our objective is to extend these models to simulate acidization in heterogeneous reservoirs where formation properties may vary both radially and vertically. Because properties may vary both radially and vertically. Because the presence of formation damage is known to be an important consideration in matrix acidizing, a near-wellbore region with properties different from the rest of the reservoir is included. Vertical reservoir heterogeneity is included in the model by division of the reservoir into multiple, noncommunicating layers with various properties. properties. Another important factor influencing sandstone-acidizing results is the vertical distribution of the injected acid. The effect of organic resin diverting agents on acid distribution was included in the model by use of the model of diverting-agent behavior presented by Hill and Galloway. Gravity segregation effects, which can have a significant impact on acid placement, were not considered in this study. The results of any particular acidizing treatment will, of course, depend on such factors as the mineral properties of the sandstone being treated, the acid properties of the sandstone being treated, the acid concentration used, and the treating temperature. In this study, conditions representative of a typical treatment were chosen. The mineral properties of a sample of Berea sandstone were used to represent the formation. An acid concentration of 3 wt% HF/12 wt% HCl was used, and, when included, the organic resin diverting agent was assumed to be 0.1 vol %. Reaction kinetics were based on a temperature of 77F [25C]. It was also assumed that carbonate minerals had been removed by an HCl preflush so that only HF reactions could be considered. preflush so that only HF reactions could be considered. The results obtained here are not intended to be representative of acidizing in a particular formation; rather, they serve to illustrate important factors that can significantly affect any matrix-acidizing treatment. The model developed was a versatile tool for studying the factors important in acidizing heterogeneous sandstone reservoirs. JPT P. 753

Enhanced Oil Recovery by CO2 Miscible Displacement in the Little Knife Field, Billings County, North Dakota

Summary A CO2 minitest involving the miscible displacement process was conducted in the Mission Canyon formation process was conducted in the Mission Canyon formation (lower Mississippian) at Little Knife field, ND. The Mission Canyon is a dolomitized carbonate reservoir at approximately 9,700 to 9,900 ft [2957 to 3018 m] subsurface, which is undergoing primary depletion. Four wells were drilled in an inverted four-spot configuration, covering 5 acres [20 234 m2]. The central well served as the injection well and was surrounded by three nonproducing observation wells. Oriented cores were cut in each well for detailed reservoir characterization and laboratory testing. In addition, a well test program was conducted that involved two pulse tests and program was conducted that involved two pulse tests and injectivity tests on the individual wells. Results from these tests were used to upgrade two reservoir simulation models. Various parameters within the computer models were modified to determine the most efficient injection plan for the specific reservoir characteristics. plan for the specific reservoir characteristics. A water-alternating-gas (WAG) type injection sequence had five alternate slugs of formation water and CO2. Preflush injection began Dec. 11, 1980, followed by the WAG slugs from Jan. 7 to March 25, 1981. Drive water injection began immediately and was completed on Sept. 24, 1981. Injection rates were maintained at 1,150 B/D [183 m3/d] during water injection and 40 ton/D [36 Mg/d] during CO2 injection. Tracers were used during the waterflood preflush and with the water during the WAG. A pressure core behind the flood front was obtained to confirm residual oil saturations in the project interval. Overall rock recovery was excellent, 90%, but sample recovery under reservoir pressure was less than anticipated. Invasion of drilling fluids during coring was checked by introduction of a radioactive tracer into the coring fluid. A compositional simulation model was used to history match the field performance of the CO2 minitest. A detailed reservoir characterization was developed and used in the simulator to match bottomhole pressures, water and CO2 breakthrough times, and fluid saturation histories at the observation wells. The effects of gravity segregation, stratification and crossflow, and reservoir heterogeneity also were investigated. The pattern sweep efficiency for CO2 approached 52% in the minitest area. Displacement efficiency, as indicated by simulation study, was 50% of the oil in place at the start of the project, compared with an efficiency of 37% for waterflood. A total of 3,100 scf CO2/ incremental bbl [558 std m3/incremental m3] of displaced oil were required. The absence of producing wells and only one zone within the Mission Canyon being flooded favorably influenced these figures. Introduction Little Knife field is near the central portion of the Williston basin (Fig. 1). The field is isolated within the broad, low lying, northward plunging Little Knife anticline, an anticlinal nose. Closure on the east, north, and west is created by the gentle anticlinal fold, with stratigraphic entrapment forming closure to the south. Production is from dolomitized, porous beds of the Production is from dolomitized, porous beds of the Mission Canyon formation. The reservoir was originally under saturated and had no free-gas saturation. The primary recovery mechanism in the reservoir is fluid primary recovery mechanism in the reservoir is fluid expansion with limited edge water drive. Since discovery in Jan. 1977, to June 1, 1984, the field has produced 31 × 106 bbl [4.47 × 106 m3] oil, 9 × 109 cu ft [1.33 × 109 m3] sour gas (1,380 GOR), and 5.8 × 106 bbl [0.92 × 106 m3] water. Oil gravity is 41 deg. API [0.82 g/cm3] with a viscosity of 0.20 cp [0.0002 Pas] and density of 0.6043 g/mL [604 kg/m3] at a reservoir temperature of 245 deg. F [118 deg. C] (Table 1). The solution GOR is 1,119 scf/STB [199.4 std m3/stock tank m3] with a saturation pressure of 2,698 psia [18 602 kPa]. Minimum miscibility pressure with CO2 is 3,400 psig [23 442 kPa]. Swelling factors of oil/CO2 mixtures is illustrated graphically in Fig. 2. The temperature effect on the hydrocarbon phase behavior in the reservoir was negligible during the minitest. The production wells surrounding the CO2 minitest site were drilled in late 1977 through early 1978 on 160-acre [647.5 × 103-m2] spacing. JPT P. 1592