Waterflooding In Oil Reservoirs Research Articles

Quantitative prediction of residual wetting film generated in mobilizing a two-phase liquid in a capillary model

This research studies the motion of immiscible two-phase liquid flow in a capillary tube through a numerical approach employing the volume of fluid method, for simulating the core-annular flow and water flooding in oil reservoirs of porous media. More specifically, the simulations are a representation of water flooding at a pore scale. A capillary tube model is established with ANSYS Fluent and verified. The numerical results matches well with the existing data available in the literature. Penetration of a less viscous liquid in a liquid of higher viscosity and the development of a residual wetting film of the higher viscosity liquid are thoroughly investigated. The effects of Capillary number, Reynolds Number and Viscosity ratio on the residual wetting film are studied in detail, as the thickness is directly related to the residual oil left in the porous media after water flooding. It should be noticed that the liquids considered in this research can be any liquids of different viscosity not necessarily oil and water. The results of this study can be used as guidance in the field of water flooding.

HYDROCYCLONE EQUIPMENT FOR PREPARATION OF WATER FOR INJECTION INTO OIL-BEARING HORIZONS WITH THE AIM OF INCREASING OIL RECOVERY

For increasing the recovery of productive aquifers used for water flooding waters from surface sources, as well as oilfield wastewater generated in the oil fields in the extraction and primary processing of oil. To ensure long-term injectivity of injection wells through which water flooding of oil reservoirs need to be cleaned from surface water sources from suspended substances, oil field waste waters from petroleum products and mechanical impurities. At Kazan state University of architecture and construction (KSUAE) developed and implemented hydrocyclone installations for the preparation of water used for injection into productive horizons So in order to prepare water for use in the system of reservoir pressure maintenance, the installation is designed without the use of reagents, consisting of a hydrocyclone installation, pressure lamella settler and filter station. To clean oilfield wastewater is designed installations, the unit is a cyclone–settler, consisting of one or two batteries discharge dogproducts hydrocyclones and pressure tanks of various designs. Research KSUAE showed that the treatment of oilfield wastewater in the pressure dogproducts cylindrical hydrocyclones is not only the separation of suspensions and emulsions of the type «oil-in-water», but also destroyed membranes around oil droplets; their enlargement occurs (coalescence); there is an increase in the degree of: emulsions of this type. All this greatly intensifies the process of after–treatment of oilfield wastewater by sedimentation. The concentration of oil products in oil field waste waters after treatment in installations of the type “block hydrocyclone – sump” is reduced from 3000 to 50–60 mg/l, and the solids content is from 200 to 50 mg/l. One of the latest developments KSUAE is to install a type “a hydrocyclone unit – cylindrical chamber –sump”, consisting of battery pressure hydrocyclones design KSUAE, cylindrical containers of the upper and lower drains and horizontal pressure of the sump. Pressure hydrocyclones that are included with the installation of “block hydrocyclone – cylindrical chamber – sump”, work as hydrodynamic kaplonstudio. Fluid flows from the upper and lower drains hydrocyclones are received in the cylindrical chamber in the form of swirling jets, the energy of which is used for further hydrodynamic treatment of oilfield wastewater: in them there is the further consolidation of the oil droplets, which increases the efficiency of the separation of emulsions of the type “oil-in-water” method of settling. The concentration of oil in oilfield wastewater decreases from 3000 to 60 mg/l, and the content of mechanical impurities from 200 to 50 mg/l. These block hydroclone installations are introduced at the enterprises of “Tatneft”. To reduce the concentration in oilfield wastewater of petroleum products and mechanical impurities up to 10 mg/l after treatment in the installation type “block hydrocyclone– sump” or “block hydrocyclone – cylindrical chamber –sump” should be dispatched to post–treatment in the filtration system, consisting of rapid filters or filters very fast and accurate. Block hydrocyclone units have high power density, compact, fully automated, are blocks full of factory manufacturing; provide an opportunity to create an effective treatment technology of oilfield wastewater with the least material and energy costs.

Dynamic Self-Optimizing Control for Oil Reservoir Waterflooding

Waterflooding is a common oil recovery method where water is injected into the reservoir for increased productivity. Optimal operational strategy of waterflooding processes has to consider proceeds realized from produced oil and cost of productions including both injected and produced water. This is a dynamic optimization problem. The problem could be solved through numerical algorithms based on traditional optimal control theory which can provide only open-loop control solutions and rely on an accurate process model. However, reservoir properties are extremely uncertain, and hence open-loop solutions based on a nominal model are not suitable for applications with real reservoirs. Introduction of feedback into the optimization structure to counteract the effect of uncertainties has been proposed recently. In this work, a novel feedback optimization method for optimal waterflooding operation is presented. In the approach, appropriate controlled variables as combinations of measurement histories and manipulated variables are first derived through regression based on simulation data obtained from a nominal model. Then a feedback control law was represented as a linear function of measurement histories from the controlled variables obtained. Through a case study, it was shown that the feedback control solution proposed in this work was able to achieve a near-optimal operational profit with only 0.45% worse than that achieved through the true optimal control (with system's properties assumed to be known a priori), but 95.05% better than that obtained with the open-loop solution under uncertainties.

Adjoint-based surrogate optimization of oil reservoir water flooding

Maximizing economical asset of oil reservoirs is a simulation-based optimization involving large-scale simulation models. In this work we propose the use of reduced-order models for solving optimization problems in oil reservoir simulation using a Lagrangian barrier method for the treatment of nonlinear inequality constraints. The optimization with reduced-order models is done by employing a trust-region proper orthogonal decomposition (TRPOD) algorithm. In addition to the POD method, we also build a reduced-order model based on a discrete empirical interpolation method. In the algorithm, the first-order gradient of the objective function is computed by using the adjoint method, while the inverse of the second-order gradient is approximated using the BFGS method. The reduced-order models involve both the forward (state) and backward (adjoint) equations. Three optimization case examples in production optimization of oil reservoirs are used to study the method. They show that the TRPOD method works efficiently while simultaneously honoring the nonlinear constraints.

A study on the microbial community structure in oil reservoirs developed by water flooding

Abstract The success of biotechnological processes for oil recovery depends on adequate understanding of the relationship between the microbial community structure and oil reservoirs conditions. This study was performed to identify the microbial community structures in 10 different types of water-flooded oil reservoirs on Sinopec Shengli Oil Field. These 10 oil reservoirs have a temperature at 55–91 °C, salinity at 3000–20,000 mg/L, and permeability ranging at 207×10 −3 –6900×10 −3 μm 2 . Some important rules found that very rich diversified bacteria and archaebacteria were identified in the oil reservoirs; these microbial organisms have functions in hydrocarbon-degradation, production of active surfactants and methanogenesis which are very valuable properties required for displacement of oil, and the microbial community structures were affected by temperature, mineralization, permeability and water displacement factors in the oil reservoirs. More abundant archaebacteria and thermophilic bacteria (Thermus, Thermincola, Thermanaeromonas) were found in high-temperature oil reservoirs. In the oil reservoir with temperature above about 90 °C, the content of thermophilic bacteria was as high as 23%, and additionally a hyperthermophilic archaea, such as Geoglobus, was also identified in the microbial community. In oil reservoirs with salinity up to 10,000 mg/L, halophilic bacteria content was 30%, which was twice as much as the reservoirs at lower salinity levels. In high salinity reservoirs, the strictly obligate anaerobic and denitrifying bacteria were not the predominant species. High permeability viscous oil reservoirs after long period of water injection resulted in significant increase of microbial diversity by doubling the species and genera number of microorganisms.

The relationship between kh and achievable rates of injection, and repercussions for large scale storage

Abstract Geologic CO2 storage (GCS) can provide meaningful reduction of CO2 emissions if implemented with large injection rates. The traditional paradigm for GCS entails injection of supercritical CO2 into a brine-filled formation with an implicit assumption that resident brine can be displaced through boundaries of the formation without adverse effects. In this paradigm, kh, the product of permeability and formation thickness, is the first order control on achievable injection rates, and the gradual buildup of pressure in the formation during the storage operation will reduce those rates. These two factors impose serious constraints on the overall storage rate. In contrast, examination of field-aggregated injection and production volumes during waterflooding operations in oil reservoirs reveals a notable lack of correlation between kh and achieved injection rates. This suggests that if CO2 storage projects are operated in the same manner as waterflooded oil reservoirs, i.e. with both injection and extraction wells, located and operated to maximize rates, then material rates of storage can be achieved regardless of reservoir kh. When applied to a large set of storage formations, this mode of operation provides an otherwise unattainable overall rate of storage while greatly reducing risks associated with elevated pressure in storage regions.

Asymptotic production behavior in waterflooded oil reservoirs: Decline curves on a simplified model

In this paper we consider a very simplified model of a mature waterflooded oil reservoir and study the asymptotic behavior in time of well’s oil production. More precisely, under assumptions on stationary points, we mathematically justify and precise classical decline laws: the oil production rate decreases like C1t−γ for some γ>1 if the nonlinear front velocity vanishes when the oil concentration S is close to vacuum (ϕ(S)=Sα with α>0). A more general law is obtained for general vanishing function ϕ at vacuum. It decreases exponentially fast like C2exp(−t) if the nonlinear front velocity does not vanish. Our calculations allow us to express constants C1, C2 in terms of physical and geometrical features of the reservoir through PDEs resolution. To the authors’ knowledge, this is the first result taking into account space variables. This could be of particular interest for the optimization process of oil production.

Application of multi-criterion robust optimization in water-flooding of oil reservoir

Most of the reported robust and non-robust optimization works are formulated based on a single-objective optimization, commonly in terms of net present value. However, variation of economical parameters such as oil price and costs forces such high computational optimization works to regenerate their optimum water injection policies. Furthermore, dynamic optimization strategies of water-flooding often lack robustness to geological uncertainties. This paper presents a multi-objective while robust optimization methodology by incorporating three dedicated objective functions. The goal is to determine optimized and robust water injection policies for all injection wells. It focuses on reducing the sensitivity to the uncertainty in the model and objective function parameters when no measurement information is assumed to be available. This work also, utilizes a derivative-free Evolutionary Multi-objective Optimization (EMO) procedure in the form of a Non-dominated Sorting Genetic Algorithm (NSGA) which attempts to find a robust Pareto-optimal solution without a priori knowledge of the reservoir dynamic models. Some modifications have been introduced to the original NSGA-II code to handle the constraints of the optimization problem. The comparative test studies clearly demonstrate superiority of the proposed methodology to give optimal robust solutions under geological uncertainties with much less standard deviations and variances. Furthermore, the optimization results demonstrate less sensitivity to the imposed time-varying economical parameters such as operation costs and oil price, revealing non-dependency of the introduced multi-objective functions.

Microbial diversity in long-term water-flooded oil reservoirs with different in situ temperatures in China

Water-flooded oil reservoirs have specific ecological environments due to continual water injection and oil production and water recycling. Using 16S rRNA gene clone library analysis, the microbial communities present in injected waters and produced waters from four typical water-flooded oil reservoirs with different in situ temperatures of 25°C, 40°C, 55°C and 70°C were examined. The results obtained showed that the higher the in situ temperatures of the oil reservoirs is, the less the effects of microorganisms in the injected waters on microbial community compositions in the produced waters is. In addition, microbes inhabiting in the produced waters of the four water-flooded oil reservoirs were varied but all dominated by Proteobacteria. Moreover, most of the detected microbes were not identified as indigenous. The objective of this study was to expand the pictures of the microbial ecosystem of water-flooded oil reservoirs.

Mechanisms of Enhancing Recovery of the Superficial Heavy Oil Reservoir

The core displacement experiments show that displacement system containing chemical agent can enhance oil recovery by over 20% comparing to water flooding. Mechanisms by which chemical agent enhance oil recovery of heavy oil reservoir water flooding are: (1) improving mobility ratio by significantly decreasing viscosity of heavy oil, volumetric sweep efficiency is improved; (2) increasing capillary number by significantly decreasing oil-water interfacial tension, oil displacement efficiency is increased; (3) changing wettability of the rock surface from oil-wet to water-wet by significantly reducing the contact angle between displacement liquid and sandstone surface, capillary force is changed from the resistance force to the motive force, the residual oil is expelled from the small pores and the wall of pores, oil displacement efficiency is significantly increased.

Thermally Active Polymer To Improve Sweep Efficiency of Waterfloods: Simulation and Pilot Design Approaches

Summary A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods. This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed. Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (Kv/Kh), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low Kv/Kh (< 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high Kv/Kh and strong water segregation. The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.

Estimation of changes in saturation and pressure from 4D seismic AVO and time-shift analysis

A reliable estimate of reservoir pressure and fluid saturation changes from time-lapse seismic data is difficult to obtain. Existing methods generally suffer from leakage between the estimated parameters. We propose a new method using different combinations of time-lapse seismic attributes based on four equations: two expressing changes in prestack AVO attributes (zero-offset and gradient reflectivities), and two expressing poststack time-shifts of compressional and shear waves as functions of production-induced changes in fluid properties. The effect of using different approximations of these equations was tested on a realistic, synthetic reservoir, where seismic data have been simulated during the 30-year lifetime of a water-flooded oil reservoir. Results found the importance of the porosity in the inversion with a clear attenuation of the porosity imprint on the final estimates in case the porosity field or the vertically averaged porosity field is known a priori. The use of a first-order approximation of the gradient reflectivity equation leads to severely biased estimates of changes in saturation and leakage between the two different parameters. Both the bias and the leakage can be reduced, if not eliminated, by including higher-order terms in the description of the gradient, or by replacing the gradient equation with P- and/or S-wave time-shift data. The final estimates are relatively robust to random noise, as they present fairly high accuracy in the presence of white noise with a standard deviation of 15%. The introduction of systematic noise decreases the inversion accuracy more severely.

FLOW OF SUSPENSIONS IN TWO-DIMENSIONAL POROUS MEDIA WITH MOBILE AND IMMOBILE LIQUID ZONES

In this paper, flow of suspensions in a 2D porous medium is considered. The porous medium consist of two zones, one of them is saturated with a mobile, pure (without any solid particles) liquid and another one is saturated with an immobile liquid. The flow of suspensions occurs with colmatation and suffosion, longitudinal and across diffusion effects and in the immobile liquid zone only, diffusion transport of particles is observed. The problem is numerically solved and the influence of colmatation-suffosion, diffusion, hydrodynamic dispersion effects on filtration and mass transport characteristics is estimated. The fields of relative concentration of particles in both mobile and immobile liquid zones, porosity, permeability, and pressure gradient in the mobile liquid zone are determined for several values of diffusion, dispersion coefficients, and colmatation-suffosion intensity coefficients. Relative current, common, and total mass fluxes of solid particles through the common boundary of the mobile and immobile liquid zones are also determined. It is shown that the presence of immobile liquid zones in porous media considerably alter both the filtration and transport characteristics. Colmatation and suffosion effects in the zone with mobile liquid influence not only the filtration and transport characteristics of this zone, but also the diffusion particle transport from the zone with the mobile liquid into the zone with the immobile liquid. Results can be important in field data interpretation during water flooding in oil reservoirs, wastewater filtration, environment protection, etc.

Feasibility study using simulation model for offshore field SZ36-1

Field SZ36-1 is a water-flooded heavy oil reservoir with high porosity and unconsolidated sand. The recovery rate is low so that it becomes a challenge for production. Time-lapse seismic data is studied to improve the oil recovery for this field. This feasibility study analyzes the possible time-lapse seismic attribute spatial distribution using dynamic data and the reservoir model to determine the optimum time to acquire a new seismic survey. Based on the study, it is found that the time-lapse seismic response for this unconsolidated sand has a strong signature due to solution gas when the reservoir pressure is below the bubble point. This indicates that acquiring a new survey after 10 years of production is appropriate for a time-lapse seismic application.

Determination of formation damage in limestone reservoirs and its effect on production

Reduction of injectivity of wells by formation damage can be of considerable magnitude during waterflooding of oil reservoirs. Variation of pH of the flowing fluid is an indicator of chemical activity occurring in the formation. High pH promotes formation damage by particle deposition within the porous media and consequently particle bridging at the pore throats. Permeability reduction is used as quantitative measure of formation damage. In this paper, the results of core flow experiments in limestone formations are presented. Effluent pH and Cl concentrations are measured at the outlet of the porous medium. Brines are prepared with sodium, calcium and potassium salts (NaCl, CaCl 2, KCl). In limestone formations, formation water, which is used in injection, and artificially prepared brine in various concentrations, caused the permeability reduction. High pH values in produced water caused the permeability reduction and consequently the pores are plugged and formation damage is observed. In alkaline flooding experiments, permeability reduction is observed as a result of high pH alkaline fluids. The permeability reduction is minimized using brines of NaCl, CaCl 2 and KCl mixtures and high oil recoveries are obtained. Suspended solid particles are released and moved with injection water when salt concentration drops below the critical salt concentration, causing the permeability reduction and formation damage. Experiments below the critical salt concentrations, resulted in a reduction in permeability values in consolidated/unconsolidated limestone samples, whereas, high pH value solutions caused a reduction in permeability values, plugged the pores and resulted in formation damage.

Decline Curve Analysis For Canadian Oil Reservoirs Under Waterflood Conditions

Abstract Decline curve analysis using type-curve matching has become an established engineering tool to evaluate long-term production characteristics of oil and gas reservoirs producing under various drive mechanisms. Decline curve analysis is often used to satisfy various regulatory requirements, to establish reserves, and to evaluate the success or failure of operational changes made during a reservoir's producing life. In this study, a detailed investigation of production decline data from 78 Western Canadian Sedimentary Basin oil pools under waterflood conditions is presented. This study demonstrates that the majority of the waterflooded oil pools follow a hyperbolic decline with decline curve exponents ("b") less than 0.5. The decline exponent "b" does not exhibit any obvious functional relationship to the type of rock, oil density, geographical area, and/or geological formation. Nonetheless, such a study provides a basis for "b" values to be expected for Canadian oil reservoirs under waterflood conditions. Introduction Decline curve analysis is one of the oldest and most extensively used methods of predicting the future performance of a producing well, a lease, or a depleting reservoir. The purpose of this study is to present an analysis of the production declines of a group of waterflooded oil pools in Western Canada to establish any obvious decline trend. All of the pools selected are located in the Western Canadian Sedimentary Basin, which covers northeastern British Columbia, the southern half of Saskatchewan, and most of Alberta. This study uses a type-curve matching technique(1) based on the general hyperbolic decline equation: Equation 1 (available in full paper) Previous Studies Fetkovich(2) reported that in a predominantly solution-gas-drive reservoir in Texas, both the primary decline and the waterflood decline appeared to have the same decline exponent "b" of 0.3. Reasons for this phenomenon were uncertain to him. Schuldt et a l .(3), indicated that waterflooded oil reservoirs are generally expected to follow hyperbolic decline behaviour, but they neither explained why this should be so nor indicated their source of information. Mead(4) wrote that pools under different producing mechanisms, waterflood or water influx, should follow exponential or hyperbolic decline with decline exponents in the range of 0 to 0.2. Lijek(5) showed that if a plot of log (WOR) versus cumulative oil produced is linear, the decline curve of the pool is either hyperbolic or harmonic, depending on whether the gross rate is constant or variable. From his experience, he concluded that the decline exponent is very close to one (that is, harmonic decline) at a constant gross rate. Currier and Sindelar's work(6) was similar to that of Lijek(5). They used log (WOR) versus cumulative oil recovery and a frontal advance cross-plot to aid them in establishing waterflood production decline trends from early data of a waterflood field in Alaska. Their study also showed that waterflood declines are harmonic or hyperbolic with a decline exponent much higher than those presented by Mead(4). In their study, cases with a straight line log (WOR) versus cumulative oil produced yielded decline exponents between 0.6 and 0.7.

The Extended Washburn Equation and Its Application to the Oil/Water Pore Doublet Problem

The equations of capillary rise or wetting-phase imbibition into a cylindrical capillary are frequently described by the Washburn equation. From this starting point, the familiar pore doublet model for imbibition into a wide/narrow pair of pores has been developed. This simple analytically soluble model can afford insights into the physics of immiscible water/oil displacements in porous media, which are of importance to waterflooding of oil reservoirs. Here, we reexamine the basis of both the Washburn equation and the formulation of the pore doublet model by incorporating a more rigorous treatment of the fluid mechanics. We have extended equations previously proposed by Szekely et al. to describe water/off displacement in a capillary and it transpires that certain additional inertial terms, which appear in the full formulation of the capillary displacement problem, may be particularly important at the pore size and aspect ratio commonly encountered within porous media. The main result of this additional physics is that the pore filling time and the relative filling order of large and small pores may change since these quantities depend on the pore aspect ratio in the extended formulation. When this fuller formulation is embedded within the extended pore doublet model, we find that the modified equations lead to different findings for certain cases, compared with previous well-known (analytical) solutions. The original pore doublet model is fully characterised by three quantities, the aspect ratio, r2/L, the ratio of capillary radii, r1/r2, and the fluid "supply," i.e., free supply or restricted supply, which is characterized by a velocity, V02. In the extended pore doublet model there is a fourth governing quantity, the pore scale Reynolds number, NRe , which describes the inertial terms in the extended Washburn equation. The resulting coupled differential equations for the extended pore doublet model do not admit an analytical solution and must be solved numerically. Under certain conditions of very restricted supply of wetting fluid (low V02), the extended model agrees very closely with the conventional pore doublet results. However, there are cases which are common at the pore scale (and pore aspect ratio) where significant differences are seen. The relevance of these findings to the modeling of imbibition processes within network models of porous media is discussed.

Underground storage of CO 2 in aquifers and oil reservoirs

Reservoir simulations of CO 2 injection into a water flooded oil reservoir show that significant amounts of oil may be recovered, and a high storage capacity of CO 2 is obtained also through displacement of water. Simulated storage capacities for CO 2 injection into an aquifer vary in the range 13–68% pore volume, depending on the prevailing displacement mechanisms.

Characterization Of Formation Damage By Particulate Processes

Abstract A model-assisted analysis of formation damage in the S and S3 facies of the Eocene B-Inferior formation in Ceuta field, Lake Maracaibo, western Venezuela, is carried out. The governing mechanisms and the estimated values of the phenomenological rate constants are determined using the formation damage model by Ohen and Ciyan. A skin factor chart is constructed based on this information as a practical measure of the formation damage potential. Introduction Reduction of injectivity of wells by formation damage can be of considerable magnitude during waterflooding of oil reservoirs. The origin of formation damage can be of chemical and mechanical caused by interaction between porous media and fluid flowing through it. Chemical damage occurs due to the incompatibility between the constituents of mineral rock and the flowing fluids. Mechanical damage can he caused either by external particle invasion, as in the case of suspended particles in completion fluids, or internal particle movement mainly influenced by hydrodynamic forces. Variation of pH of the flowing fluid is an indicator of the extent of chemical activity occurring in the formation. Dissolution of cementing - authigenic materials such as carbonates and/or ion exchange between fluid and minerals can cause pH variation, High pH (alkaline media) promotes formation damage by particle deposition within the porous media and consequently particle bridging at the pore throats. Occasionally, the particle bridges brake causing temporary permeability increase. This is reflected by the pulsating character of the pressure differential and permeability reduction data. Permeability reduction and skin factor are used as quantitative measures of formation damage. A detailed description of the processes involving formation damage of porous media is given in the literature(l-14). This paper presents a model-assisted anaIy;is of formation damage in sandstone core samples belonging to the facies S and S3 of the Eocene B-Inferior formation, in Ceuta field, Lake Maracaibo, western Venezuela. The details of this study are given by Millan(l5) Due to the high content of carbonaceous and siliceous type authigenic materials the Ceuta field core samples are extremely sensitive to brine, rendering the pH toward alkaline media during waterflooding. As a result particles tend to disperse to reduce the formation permeability. Permeability alteration process is numerically reproduced by means of the Ohen and Civan model(l2) and extended beyond the experimental range. The values of the phenomenological rate constants involving the hydrodynamic and electrochemical processes, which controls the trapping and/or release of particles within the porous media, are determined and a skin factor chart is constructed using the Ohen and Civan method(13).

Experience With Fireflooding In Countess 'B' Pool, Alberta Reservoir Aspects

Abstract This paper discusses the reservoir aspects of the Countess ‘B’ Fireflood Pilot Project in southeastern Alberta. The Countess 'B J Pool is a Glauconitic channel sandstone and has been under waterflood since 1973. The fireflood pilot was initiated in 1983 and the operation is expected to continue until 1991. This 16 ha inverted five-spot includes one injector and four producers. The pilot was designed to determine the level of incremental recovery that could be achieved from the process application and to obtain operating experience from a reservoir containing 28 ° API oil. An extensive program of well testing and fluid analysis has been conducted to identify and evaluate the pilot performance. The Countess ‘B’ Fireflood Pilot has broken new ground in a number of ways. Results suggest that a waterflooded light oil reservoir can be fireflooded successfully. A mineralogical examination of a post-combustion core indicates that firefront temperature in this pool is 300 °C to 400 °C and oil is effectively displaced. To the end of 1988, the cumulative burned volume represented 20% of the pilot volume. To date the pilot has achieved most of its objectives and will likely achieve the remaining objectives prior to its termination in 1991. Introduction The Countess Upper Mannville ‘B’ Pool is located in Township 19, Range 16W4M, approximately 20 km west of the town of Brooks. Alberta (Fig. I). This pool is part of the Countess Latham trend and was discovered in 1965. The pool is operated by PanCanadian Petroleum Limited and jointly owned (50%) with LL&E Canada Ltd. The pool is currently in the later stages of waterflood. Extensive engineering and laboratory studies conducted on the Countess ‘B’ Pool during the period 1978–80 concluded that fireflooding application is feasible. A pilot project commenced in January 1983 in Part II of the Countess ‘B’ Pool to evaluate the fireflood process and is expected to continue until 1991. Reservoir In the Countess ‘B’ Pool, oil production is from a series of southeast/northwest trending channel sands. These sands are elongate and narrow with a length of up to 5 km and a width ranging from 300 m to 1500 m. Thickness varies from 1 m to 12 m. Based on lithology and stratigraphic position, the sandstones of the Countess ‘B’ Pool are part of the "'Glauconitic" of the Upper Mannville Group. Part II of the Countess "B' Pool, as shown in Figure 2, is the largest of these sands. Following are the average reservoir properties of Pan II:depth 1080mgross pay thickness 8 mporosity 25%permeability 800 mDinitial oil saturation78%initial reservoir pressure 9.6 MPareservoir temperature 38 °Coil gravity28 °C APIoil Viscosity @ reservoir conditions 6 cpinitial formation volume factor 1.124 The Glauconitic sandstones of the Countess ‘B’ Pool are generally fine- to medium-grained, moderately well sorted and composed of quartz and chert with minor feldspar and decrial clay. Cementation is mainly by authigenic clays, including kaolinite and to a lesser degree illite.