Bottom Water Zone Research Articles

Numerical simulation investigations of the applicability of THAI in situ combustion process in heavy oil reservoirs underlain by bottom water

The presence of a bottom water (BW) layer in heavy oil reservoirs can present substantial problems for efficient oil recovery for all recovery techniques. Hence, it is necessary to know how particular production processes are affected by different BW layer thicknesses, and how standard production procedures can be adapted to handle such reservoirs. Toe-to-heel air injection (THAI) is a thermally efficient process, generating in situ energy in the reservoir by burning a fraction of the oil-in-place as coke and has the potential to economically and environmentally friendly work in reservoirs with BW layer. However, to ascertain that, studies are needed first. These are conducted via numerical simulations using commercial reservoir thermal simulator, CMG STARS. This work has shown that the shape of the combustion zone in THAI remains forward-leaning even in the presence of a BW layer, indicating that the process is stable, and that there is no oxygen bypassing of the combustion front. However, the oil recovery rate is highly negatively affected by how large the thickness of the BW zone is, and the severity of such effect is determined to be proportional to the thickness of the BW layer. This study also shows that there is a period of low oil production rate which corresponds to mobilised oil displacement into the BW zone which in turn causes a surge in water production rate. The practical implication of this is that prolonged period of low oil production rates will expose companies and/or investors to higher risk due to the oil market volatility. In this study, it is also revealed that the height of the mobilised oil that is displaced into the BW zone equates to that of the displaced and replaced water thereby implying that when the BW layer thickness is 50% that of the oil layer (OL), less than 50% of the mobilised oil will be recovered when the entire reservoir is swept by the combustion front. Therefore, conclusively, applying the THAI process in its conventional form in reservoirs containing bottom water is not recommended, and as a result, a new strategy is needed to enhance process economics by improving the oil production and hence recovery rates.

Influence of top water on SAGD steam chamber growth in heavy oil reservoirs: An experimental study

Steam-assisted gravity drainage (SAGD) is one efficient and mature technology for recovering heavy oil and bitumen resources. The key underlying mechanism is the growth of the steam chamber after injecting steam. However, due to the complex geological environment, the thief zones exist and have a prejudicial effect on the development of the steam chamber, thus impacting the ultimate heavy-oil recovery. In this work, our objective is to investigate the effect of a top-water thief zone (i.e., water zone overlies the oil sand) on SAGD performance and further to understand the crucial mechanisms that control the heat loss during steam injection. A large-scale three-dimensional experimental apparatus is used to carry out the SAGD process with a top aquifer. Based on the similarity criterion, the field-scale model is transformed into a laboratory elemental model. To evaluate the SAGD performance quantitatively, the dynamic growth of the steam chamber is measured using the thermal detectors and the production data is recorded. The results show that the steam chamber exhibits three distinguished stages, that is, upward spread, lateral extension, and downward development in the presence of top-water zone. The bottom-water zone has less impact on the steam-chamber growth. The existence of a confined top-water zone, however, significantly affects SAGD performance, especially the lateral expansion of the steam chamber. The lateral propagation of the steam front is hindered by the top thief zone due to the heat exchange with the top water. Once the steam chamber reaches the boundary, the accumulation of energy in the water thief zone, in turn, can reduce the remaining oil saturation along the topwater–oil interface. This study provides us some key insights into the development of heavy oil resources with top thief zones when implementing SAGD technology.

Simulation study on the effect of reservoir bottom water on the performance of the THAI in-situ combustion technology for heavy oil/tar sand upgrading and recovery

Some of the bitumen/tar sand/heavy oil reservoirs are underlain by bottom water (BW) layer, which often severely affects the performance of thermal EOR (enhanced oil recovery) processes. The effect of bottom water on the performance of the toe-to-heel air injection (THAI) in-situ combustion (ISC) process is investigated through reservoir simulation using CMG STARS simulator. The current study has shown that there is a limit to BW thickness above which the performance of the THAI process is affected even though the combustion front propagated stably. It is found that the thickness of the ‘‘basal gas layer’’ (BGL) depends on how further down into the BW zone the horizontal producer (HP) well is located. From this study, it is found that the critical BW thickness, when the THAI process is implemented in any heavy oil BW reservoir with the wells arranged in an SLD (staggered line drive) pattern, should lie in the range of 50% OL (oil layer) < BW (bottom water) < 100% OL (oil layer). A comparative study between the active and non-active aquifers models shows that the same cumulative volume of water is produced and that over the 715 days of the process, only negligible amount of oil is produced from BWN (i.e. static aquifer model). It is found that in neither of the models does oxygen bypass the combustion front and as in the previous studies, both fronts are restricted to the upper part of the reservoir, within the oil zone. Therefore, it follows that even in the presence of active aquifer (i.e. BWA model), the THAI process still operates stably in terms of combustion front propagation and sustenance. For the combustion initiated at the oil–water (O–W) interface, it is found that controlled gravity override resulted in a high rate of advancement of combustion front at the top of the reservoir. The combustion is observed to not propagate along the BGL, rather, it propagates as though it is initiated at the top of the reservoir. It is shown that the BGL is only formed during the early period of air injection as the combustion gases could not reach the HP well without displacing the water to create initial gas flow pathway into the HP well. It is also observed that initiating the combustion at the oil–water interface results in a massively improved oil recovery rates, most especially when implemented in the DLD (direct line drive) pattern.

Mathematical model study on the damage of the liquid phase to productivity in the gas reservoir with a bottom water zone

Abstract The production process in the gas reservoir with an aquifer is complex. With gas production, aquifer water could possibly flow into the production well and accumulate within the well bore, which leads to a lower production rate and may even block the producer. However, few studies in the literature investigate the damage caused by the liquid phase in this kind of reservoir or predict gas productivity using the relationship between reservoir pressure and water gas ratio (WGR). For this reason, it is important to know the effects of the formation of liquid phase behavior on production when an aquifer is present under a gas reservoir. From the results of published literature reviews, we found that studies focused on the production of a gas reservoir with bottom water. Nevertheless, for gas well damage from the liquid phase behavior, we found that there was no statistical data or mathematical model of the relationship between reservoir pressure and the gas oil ratio (GOR), which affects production. In this research, based on the theory of fluid flow in porous media, a new mathematical model of water and gas production and a new equation on gas well productivity is developed. To verify the model and equation, gas production data collected from the field are applied. By analyzing the typical gas reservoir with bottom water and the collected data, influences from the liquid phase behavior are shown. In this way, mathematical relationships between reservoir pressure and the WGR and between the GOR and production decline were obtained. The new gas productivity model is derived from the gas and water pseudo pressure functions, which can be applied to analyze well damage caused by the liquid phase. In order to verify the mathematical model, production data were collected from a typical gas reservoir with an aquifer located in the Changxing gas reservoir. The results indicate that a semi-logarithmic linear relationship is obtained between the WGR and productivity decrease. When the WGR increases from 0.5 to 15 m 3 /10 4 m 3 , damage caused by liquid phase decreases to 59%. The tendency of gas productivity in the Changxing gas reservoir was obtained so that it decreases as reservoir pressure decreases and increases as the WGR decreases. The gradient of the gas productivity deduction increases as the WGR increases. By the end of the data analysis, two linear equations indicating the relationship between gas productivity and reservoir pressure and the relationship between gas productivity and the water gas ratio are obtained: Q A O F = − A 1 l n W G R − B 1 and Q A O F = A 2 l n P − B 2 , respectively. The new model and these two equations can be applied to predict gas productivity in the gas reservoir with an aquifer and determine the damage level to the gas well. They also can be used to guide development plans in the gas reservoir with an aquifer.

Numerical Simulation Study on Steam-Assisted Gravity Drainage Performance in a Heavy Oil Reservoir with a Bottom Water Zone

In the Pikes Peak oil field near Lloydminster, Canada, a significant amount of heavy oil reserves is located in reservoirs with a bottom water zone. The properties of the bottom water zone and the operation parameters significantly affect oil production performance via the steam-assisted gravity drainage (SAGD) process. Thus, in order to develop this type of heavy oil resource, a full understanding of the effects of these properties is necessary. In this study, the numerical simulation approach was applied to study the effects of properties in the bottom water zone in the SAGD process, such as the initial gas oil ratio, the thickness of the reservoir, and oil saturation of the bottom water zone. In addition, some operation parameters were studied including the injection pressure, the SAGD well pair location, and five different well patterns: (1) two corner wells, (2) triple wells, (3) downhole water sink well, (4) vertical injectors with a horizontal producer, and (5) fishbone well. The numerical simulation results suggest that the properties of the bottom water zone affect production performance extremely. First, both positive and negative effects were observed when solution gas exists in the heavy oil. Second, a logarithmical relationship was investigated between the bottom water production ratio and the thickness of the bottom water zone. Third, a non-linear relation was obtained between the oil recovery factor and oil saturation in the bottom water zone, and a peak oil recovery was achieved at the oil saturation rate of 30% in the bottom water zone. Furthermore, the operation parameters affected the heavy oil production performance. Comparison of the well patterns showed that the two corner wells and the triple wells patterns obtained the highest oil recovery factors of 74.71% and 77.19%, respectively, which are almost twice the oil recovery factors gained in the conventional SAGD process (47.84%). This indicates that the optimized SAGD process with the two corner wells and the triple wells pattern is able to improve SAGD production performance in a heavy oil reservoir with a bottom water zone.

A semi-analytical model for predicting inflow profile of horizontal wells in bottom-water gas reservoir

In this study, a semi-analytical model which couples the reservoir and wellbore, is developed to predict the inflow profile of horizontal wells in a box-shaped gas reservoir with a bottom water zone. The developed gas reservoir flow model is based on a 3D volumetric source model which considers the reservoir properties in the region near the wellbore, in terms of anisotropy, heterogeneity and formation damage. Meanwhile, pressure drops in the wellbore flow model was also considered, due to fluid flow in the horizontal wellbore. The model was calculated by a field case, and the results of the calculation were compared with a commercial simulator: ECLIPSE (Schlumberger, 2011). The comparison between the developed model and ECLIPSE indicates that, a good match was obtained, so that, the model derived in this study can be applied to predict the inflow profile of horizontal well in a gas reservoir with bottom water zone. Moreover, sensitivity analysis is conducted by using various wellbore pressure drops, wall roughness, skin factors, wellbore diameters, anisotropy and producing pressure drops.

Optimized solvent-aided steam-flooding strategy for recovery of thin heavy oil reservoirs

Stochastic optimization based on a simulated annealing method was carried out to determine the optimum steam and steam–solvent flooding strategies in a thin (4m) heavy oil reservoir both in the absence and presence of a bottom water zone. The steam injection pressure optimization case determined a technically feasible operating strategy. However, the cumulative energy to produced oil ratio (cEOR) realized from the optimized process is high. In comparison, the solvent-aided steam optimization case achieved an operating strategy with a much lower cEOR and cumulative water-to-oil ratio (cWOR) than those in the optimized injection pressure-only strategy. We observed that a solvent-rich channel forms at the top of the reservoir after solvent breakthrough occurs at the production well. The formation of the solvent-rich channel led to oil–solvent mixing at the periphery of the channel as well as heat transfer to oil beyond the channel, which in turn resulted in better recovery performance. In the presence of a bottom water zone, the optimized steam injection pressure optimization strategy was found to perform poorly. However, the optimized solvent-aided strategy achieved superior performance. With solvent injection, the presence of the bottom water zone enhanced mixing of solvent and oil yielding improved oil recovery performance.

Short-term euxinia coinciding with rotaliporid extinctions during the Cenomanian-Turonian transition in the middle-neritic eastern North Atlantic inferred from organic compounds

Oceanic anoxic event 2 (OAE2), which occurred during the Cenomanian-Turonian (C-T) transition and lasted 1 m.y., is characterized by a positive global carbon isotopic excursion and stepwise extinctions in marine biota. To examine temporal variations in the dissolved oxygen content of the water column, shallow-marine C-T sediments from northern Spain were analyzed for concentrations of dibenzothiophenes, which are indicators of euxinic depositional environments, and 2,3,6-trimethylarylisoprenoids, which probably indicate photic-zone euxinia. The positive excursion in δ 13 C values of carbonates is accompanied by short-term (10 3 –10 4 yr) and long-term (10 5 yr) increases in dibenzothiophene and 2,3,6-trimethylarylisoprenoid concentrations, suggesting that the bottom water and photic zone of the eastern marginal sea of the North Atlantic Ocean were euxinic. Two of the short-term increases in organic compound concentrations took place just after the last occurrence of the planktonic foraminifers Rotalipora greenhornensis and R . cushmani . These transient maxima indicate that the extinction of both planktonic foraminifers was due to short-term OAEs lasting 10 3 –10 4 yr.

Review of Thermal Recovery Technologies for the Clearwater and Lower Grand Rapids Formations in the Cold Lake Area in Alberta

Summary Cyclic Steam Stimulation (CSS) has been a commercial recovery process since the mid 1980s in the Cold Lake area in northeast Alberta. The current bitumen production is over 220,000 B/D using CSS from this area. To achieve desired injectivity in the bitumen saturated reservoir, steam is usually injected at a pressure above or close to the fracture pressure of the formation. A relatively high pressure drawdown is created between the wellbore and formation during the production phase, particularly in the early stage of the production cycle where formation compaction and solution gas drive are the two most important recovery mechanisms. The CSS process has limited application in reservoirs with thick bottom water or in reservoirs with fine grain sands. The Steam Assisted Gravity Drainage (SAGD) process has been field tested and commercially expanded in the Lower Grand Rapids and Clearwater Formations in the Cold Lake area. In contrast to CSS, SAGD is a continuous steam injection process that relies on gravity and requires a minimum pressure drawdown to drive the reservoir fluids to the wellbore. This provides a significant advantage for SAGD as an option for the reservoirs with bottom water, top gas or with formations with fine grain sands. Several SAGD projects are in operation in different types of reservoirs in the Cold Lake and Lloydminster areas; some with thick bottom water zones. A performance review is conducted based on the available data for various CSS and SAGD projects in the Cold Lake area. The selection criteria between CSS and SAGD technologies for Clearwater and Lower Grand Rapids are discussed. Reservoir modeling results are presented concerning the impact of well placement, reservoir heterogeneity and operating parameters on SAGD performance, based on Osum's Lower Grand Rapids and Clearwater geology in the Cold Lake area.

Experimental Study of Solvent Flooding to Heavy Oil in Fractured Five-Spot Micro-Models: The Role of Fracture Geometrical Characteristics

Abstract The solvent-based process appears to be an increasingly feasible technology for the extraction of heavy oil reserves. However, there is a lack of fundamental understanding of how fracture geometrical characteristics control the oil recovery efficiency in this type of enhanced oil recovery (EOR) technique. In this work, a series of experiments were performed whereby the pure and mixed hydrocarbon solvents (HCS) displaced heavy oil in fractured five-spot glass micro-models. Successive images of the solvent injection process were recorded. The oil recovery factor, as a function of injected pore volume of solvents, was measured using image analysis of the provided pictures. It has been observed that the oil recovery decreased when the fractures' spacing, discontinuity, overlap, and distribution increased. In contrast, the oil recovery increased when the orientation angle, discontinuity-distribution and the number of fractures increased. Also, it has been found that there is an optimum solvent composition, which maximizes the oil recovery. Finally, some pore-level visualization representing the role of asphaltene precipitation during miscible injection was illustrated using these experiments. This study demonstrates the applicability of the micro-models for the fundamental studying of the solvent-based process in fractured five-spot systems, which are used to investigate the effect of fracture geometrical characteristics and their effect on oil recovery. Introduction Heavy oil and bitumen reserves represent a considerable portion of worldwide energy resources. It is estimated that these reservoirs contain six trillion barrels of oil originally in place (OOIP), which is much more than the total conventional oil reservoirs. Great consumption of light oil reserves and their resulting dramatic decline encourages more interest in exploitation of highly viscous oil and bitumen for future energy demands. For optimum conditions, the primary recovery of these reservoirs would not exceed 10% of the OOIP(1). A variety of thermal methods, including cyclic steam stimulation, in-situ combustion and steam assisted gravity drainage are currently being applied for extraction of these crudes. As far as the reservoir's oil is heated, the main fraction of thermal energy is used up in heating the formation itself. For the reservoirs with a thin pay zone, bottom water zone and/or overlying gas zone, excessive depths, low thermal conductivity of rock matrix, high water saturation, etc., the economical applicability of thermal methods is doubtful. With respect to current available recovery technologies, these reservoirs are categorized as problematic reservoirs(2,3).

Economic Optimization and Uncertainty Assessment of Commercial SAGD Operations

Abstract As SAGD is being increasingly used as a commercial technology to recover heavy oil and bitumen, it is essential to determine the most economical operating conditions for a SAGD operation by reservoir simulation. Furthermore, to support the decision-making process of a SAGD project, it is also important to quantitatively assess the uncertainty of its economicforecasts. In this paper, the application of global optimization, experimental design, response surface generation and Monte Carlo simulation techniques in the workflow of SAGD simulation studies were demonstrated with a real field case example. The field case is an infill SAGD project with two planned SAGD well pairs and eight existing primary production wells which have 5 years of primary production. A bottomwater zone is also present. Three major steps of the workflow are:history matching primary production data;optimizing SAGD performance; andquantifying uncertainty of the SAGD forecasts. Firstly, experimental design and DECE (Designed Exploration and Controlled Evolution) optimization methods were used to achieve a faster and better history match than the traditional manual history match. Secondly, SAGD performance was optimized by adjusting the steam injection rate and producer liquid withdrawal rate during different SAGD operation periods. Finally, experimental design and response surface generation techniques were applied to build a polynomial response surface through which the net present value (NPV) of the SAGD project is correlated with uncertain parameters and a SAGD design parameter. Monte Carlo simulation was then performed to quantify the uncertainty of SAGD forecasts in terms of cumulative probability distribution of the NPV at different values of the SAGD designparameter. The results show that the economics of this project are improved considerably through optimization. The optimum operating conditions obtained use a high initial steam rate and high production rate to develop the steam chamber. After the instantaneous steam-oil ratio reaches a certain value, both steam rate and production rate are lowered to prevent steam breakthrough to the bottomwater. The uncertainty of the project NPV was assessed, taking into consideration the uncertainties in high temperature relative permeability endpoints and the variation of the SAGD design parameter. Introduction Steam-assisted gravity drainage (SAGD) is a thermal oil recovery process which consists of pairs of two parallel horizontal wells drilled near the bottom of the pay(1). Typically, the length of the wells are between 500 and 1,000 m, the inter-well distance of the two parallel wells is between 5 and 10 m and inter-well pair spacing is between 90 and 120 m(2, 3). The top horizontal well is used to inject steam, while the bottom horizontal well is used to produce reservoir fluids. The steam injected from the top well rises into the formation, forming an expanding steam chamber around and above the injection well. The rising steam eventually loses its latent heat near the boundary of the steam chamber, heats the oil and allows it to drain to the bottom production well by gravity. Successful field tests have proven that SAGD is a viable technology for in situ recovery of heavy oil and bitumen(4–6).

Bottomwater Reservoirs:Simulation Approach

Abstract In many light or moderately viscous oil reservoirs in Saskatchewan and Alberta, a high inactive water saturation zone of varying thickness and extent (bottom water zone) occurs in communication with the oil zone above. As a result, the primary production period is short, and water breakthrough occurs very early in the life of the reservoir. Later, during the secondary recovery stage, such a zone can have an adverse effect on the waterflood efficiency. This paper addresses the problem of waterflooding such reservoirs. This study was directed towards reducing water mobility in the bottomwater zone for more efficient oil displacement. A commercial simulator (CMG's IMEX) was used to conduct this small scaled study. Polymer in various concentrations was used as a plugging agent in the bottomwater zone and as a mobility control agent in the oil zone. Different strategies were investigated to reduce water mobility in the bottomwater zone and improve the vertical sweep efficiency. The variables examined were: permeability ratio, oil viscosity, relative water-to-oil layer thickness, polymer concentration, injection rate and injection point, as well as the effect of vertical and horizontal injection and production well combinations. The results showed that minimizing crossflow between layers by plugging the bottom water zone could increase oil recovery. It was also found that for an unfavourable mobility ratio, as the injection rate increases, the ultimate oil recovery increases. The injection of a polymer solution had a favourable impact on waterflood performance. Moreover, the worse the conventional waterflood performance was, the more effective the polymer was as a mobility and plugging control agent. The use of horizontal wells showed slightly better oil recovery over vertical wells in a conventional waterflood of reservoirs under bottomwater conditions. In addition, some certain well combinations (horizontal production and vertical injection) gave better oil recovery due to the increase in the swept area. Introduction The efficient and economic recovery of oil from reservoirs under bottom water conditions is recognized as a formidable task. High water cuts and rapidly decreasing oil rates early in the production life of such reservoirs have, in many instances, prompted their suspension or abandonment at very low levels of oil recovery. Reservoir characteristics and rock and fluid properties combine to yield the single most important parameter (mobility ratio) in a waterflood. A number of chemicals such as polymers, emulsions, biopolymers, foam and carbon dioxide-activated silica gel have been used to control the mobility ratio. One of the oldest techniques to control mobility of water in waterflooding is the use of polymers. This control agent was shown to be effective in the early sixties by Pye(1). He performed numerous field and laboratory studies of polymer flooding using polyacrylamide solutions. It was observed experimentally that the viscosity of the water-soluble polymer solutions measured in the formation sample departed markedly from that obtained using a viscometer. He quantified the unusual departure of the measured values from the expected response as the resistance factor. It was assumed that the permeability was constant.

On seasonal variations of radiocesium speciation in the surface sediments of Lake Juodis, Lithuania

Data on radiocesium speciation measured seasonally in black silt surface sediments in the shallow terrace and in the deepest southern part of Lake Juodis (Lithuania) in 2004–2005 are presented. It is shown that seasonal variations of radiocesium exchangeable fractions in the sediments in the shallow terrace are mainly related to its redistribution due to the vital cycle of green algae covering bottom surfaces – processes of their growth and decomposition. A seasonal course of those fractions in surface sediments of the deepest bottom areas of the lake follows a distinct pattern and is annually recycling. It is maximum in winter and declines due to stagnant bottom water zone disruption in summer. It is shown that surface sediments in the deepest bottom areas of the lake are not a radiocesium source during the formation of the anaerobic zone in bottom water in winter, and act in that case as its acceptor. The radiocesium remobilization to the bottom water is seasonal and site-specific. It is suggested to be due to three main processes: its diffusion from deeper and more active sediments, its redistribution during decomposition of organics freshly accumulated in surface sediments and a radiocesium flux induced by the mechanism of the seasonal anaerobic zone formation in near-bottom water.

Evaluation of the Bottom Water Reservoir VAPEX Process

Abstract In 1998, Butler and Mokrys proposed a "Closed-Loop Extraction Method for the Recovery of Heavy Oils and Bitumens Underlain by Aquifers." The process has potential application to many Alberta and Saskatchewan heavy oil reservoirs. The objective of our work was to produce an experimental evaluation of solvent-assisted process options for bottom water reservoirs. The current work is entirely experimental, and provides data that may be used to back up a numerical simulation effort. The experimental series modelled a bottom water process in order to determine its feasibility for a field-scale oil recovery scheme. A series of five experiments were run in an acrylic visual model. Pujol and Boberg's scaling criteria(1) were used to produce a lab model scaling a field process by a geometric ratio of 100:1, and compressing field time by a ratio of 10,000:1. The model simulated a slice of a 30 m thick reservoir with a 10 m thick bottom water zone, containing a pair of horizontal wells at the oil-water interface, offset by 25 m. For field prediction, experimental results were scaled up to represent a 30 m thick reservoir (20 m thick oil zone) with 500 m horizontal wells. The experimental rates were negatively impacted by continuous low permeability layers and by oil with an initial gas content. The lower effective diffusion rates required that the surface area exposed to solvents be increased in order to achieve commercial oil recovery rates. The Bottom Water Process described in this report offers the opportunity to do just that, as the large surface area of the oil water interface between the wells will provide contact for solvent by injecting gas at the interface. Given an appropriate well spacing, high production rates should be possible. Introduction The Alberta Research Council (ARC) has done several years of investigative work into solvent-assisted heavy oil recovery processes(2, 3). The present report describes a particular contribution to solvent-assisted oil recovery technology; a comparative scaled physical model study of bottom water process options. The results of this work showed scaled field rates of 25.3 m3/d and a live oil scaled rate of 16.5 m3/d, both at 25 m offset well spacing. Mechanisms of the Bottom Water VAPEX Process The Bottom Water VAPEX Process, illustrated in Figure 1, is a recovery process depending on the interplay of several mechanisms for its success. The solubility of the gas in the oil is controlled by the k-values of the oil/solvent system. Diffusion, hydrodynamic dispersion, and swelling also play a role in the movement of gas into the reservoir oil. The oil flow is enabled by viscosity reduction due to the dissolution of solvent in the oil. Oil-solvent contact is further augmented by capillary pressure moving some oil into the vapour chamber zone, as was observed in Experiment #2. Heterogeneity of the reservoir sand further increased the surface produced by capillary action, but excessive layering can hinder the movement of oil, as was shown by Experiment #3.

Methane Pressure-Cycling Process With Horizontal Wells for Thin Heavy-Oil Reservoirs

Summary The methane pressure-cycling (MPC) process is an enhanced-oil-recovery (EOR) scheme intended for application in some heavy-oil reservoirs after termination of either primary or waterflood production. The essence of the process is the restoration of the solution-gas-drive mechanism. The restoration is accomplished by re-injecting an appropriate amount of solution gas (mainly methane) and then repressuring the gas back into solution by injecting water until approximate original reservoir pressure is reached. This, aside from the replacement of produced oil by water, recreates the primary-production conditions. This novel recovery technique is being developed to target the considerable portion of heavy-oil resources located in thin reservoirs. Primary and secondary methods have managed to recover at best 10% of the initial oil in place (IOIP). Heat losses to overburden and underburden or bottomwater zones make thermal methods unsuitable for thin reservoirs. Sandpack-flood tests in 30.5-cm (length)×5.0-cm (diameter) sandpacks were carried out for oils with a range of dead-oil viscosities from 1700 to 5400 mPa·s. The results showed that the pressure-cycling process could create a favorable condition for recharged gas to contact the remaining oil in reservoirs. This restores the situation whereby substantial amounts of gas are in solution for further "primary" production. The effects on the efficiency of the MPC process of cycle termination strategy, oil viscosity, and mobile-water saturation were investigated. Simulations were conducted to investigate the MPC process in three heavy-oil reservoirs in Saskatchewan, Canada. The effects on the process of infill wells, oil viscosity, gas-injection rate, and the presence of wormholes in reservoirs were studied.

Steam Injection in Oil Reservoirs With Bottom Water Zone

3-D scaled model was used to study the performance of steam injection in reservoirs having a bottom water zone with the application of different well configurations. 3-D laboratory model was designed to represent ¼th of a 5-spot pattern in the B. Kozluca field in Turkey. Four experiments were conducted with the rectangular model with or without bottom water zone. The well configurations were changed during the course of experiments to determine their effects on oil recovery. Bottom water thicknesses were changed to see the effetcs on oil recovery. The physical properties of crushed limestone and crude oil mixture were kept constant during the experiments. Steam was injected through a vertical injection well in the model. Strings of thermocouples were used to observe 3-D temperature distribution. The maximum oil recovery was obtained by placing the horizontal producer along the diagonal of the rectangular model. Vertical injection-horizontal production well configuration provided better oil recovery than other well configuration even in the presence of a bottom water zone. Oil recoveries decreased with an increase in the thickness of the bottom water zone. Steam-oil ratio (SOR) increased in the presence of bottom water zone.

Methane Pressure-Cycling Process for Thin Heavy-Oil Reservoirs

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 88500, "Methane Pressure-Cycling Process With Horizontal Wells for Thin Heavy-Oil Reservoirs," by Mingzhe Dong, SPE, PTRC, and Sam Huang, SPE, and Keith Hutchence, SRC, prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October. The methane pressure-cycling (MPC) process is an enhanced-oil-recovery (EOR) method used in some heavy-oil reservoirs after termination of primary or waterflood production. The object of the process is restoration of the solution-gas-drive mechanism. This restoration is accomplished by reinjecting an amount of solution gas, mainly methane, and then repressuring the gas into solution by injecting water until the original reservoir pressure is reached. This recreates the primary-production conditions. This recovery technique targets the large portion of heavy oil in thin reservoirs. Introduction Heavy oil in reservoirs thicker than 10 m commonly is produced by use of thermal recovery methods. These methods generally are not suitable for thin reservoirs because of heat losses to the overburden, underburden, and bottomwater zones. Saskatchewan accounts for 62% of Canada’s total heavy-oil resource including 1.7×109 m3 of proven and 3.7×109 m3 of probable reserves. Of the province’s proven initial heavy oil in place, 97% is contained in reservoirs with pay zones less than 10 m thick and 55% is in reservoirs with pay zones less than 5 m thick. Primary and secondary methods recover only approximately 7% of the proven initial oil in place (IOIP). The incentive is strong for the development of EOR techniques that will maximize the recovery of these thin heavy-oil reservoirs. The MPC process is an EOR method intended for application after termination of primary or waterflood production in some thin reservoirs. The objective of the pressure-cycling process is restoration of the solution-gas-drive mechanism that provided primary production. Restoration is accomplished by reinjecting an amount of solution gas and then repressuring the gas back into solution by injecting water until original reservoir pressure is reached. This recreates the primary-production conditions. The process uses infill horizontal production wells located between the existing vertical wells that are used for methane and water injection to pressure up the depleted reservoir. This pressure cycling is repeated until additional economic recovery is no longer feasible. The Saskatchewan Research Council/Petroleum-Technology Research Center has been investigating the pressure-cycling process for the past few years. Experimental Pressure/Volume/Temperature (PVT) Studies. PVT studies were conducted for oil samples collected from four Saskatchewan heavy-oil reservoirs (Senlac, Golden Lake, Plover Lake, and Cactus Lake North) in contact with methane. The purpose of these studies was to investigate the PVT properties of heavy-oil/methane mixtures and to provide input data on the PVT behavior of live oils for numerical simulations. Heavy-Oil Coreflood Studies. The heavy-oil coreflood apparatus consists of a 30.5-cm triaxial-stress core holder, a Ruska dual-cylinder positive-displacement pump, an injection system, a production system, and support units. A backpressure regulator installed at the production end maintained the operating pressure. Oil production was determined on a mass basis.

Seven-Spot Steam Injection Experiments in Heavy Oil Reservoirs Having a Bottom Water Zone

A 3-D scaled physical model was used to compare the performance of steam injection in reservoirs having a bottom water zone with the application of different well configurations. The model was tria...

An Investigation of Polymerflooding in Limestone Reservoirs with a Bottom Water Zone

The effects of polymers on waterflooding of a limestone reservoir with or without a bottom water zone, as well as the effect of vertical and horizontal production wells on oil recovery, have been investigated in laboratory models. Sixteen core flood displacement tests were conducted to study the effect of relative oil-water layer thickness, polymer slug size, and well configuration in a production port. A qualitative comparison was made to show the difference between waterflooding and polymer-augmented waterflooding runs, where a light crude oil with a viscosity of 14.5 mPa.s was used. The results of the displacement tests showed that as the thickness of the bottom water zone increases, the ultimate oil recovery decreases. The selected polymer solution had a favorable impact on the waterflood performance. However, the worse the conventional waterflood performance was, the more effective was the polymer as a mobility control agent. For instance, when the bottom water zone was approximately as thick as the oil zone, only about 25% of Original Oil in Place (OOIP) was recovered by a waterflood, whereas with a polymer as the mobility control agent, more than 55% of OOIP was recovered. For polymer injection, the effect of slug size was discussed with the aid of concentration curves and retention rate values; and a slug of 0.60 PV was obtained as optimal. In a conventional waterflood, the horizontal production well showed slightly better oil recovery than the vertical production well with a thin bottom water zone. In polymer-augmented waterflooding, higher oil recoveries were obtained with vertical production wells as compared to horizontal production wells. This was because of the early production of polymer solutions and reductions of the swept area from investigation of concentration curves.

An Investigation of Polymerflooding in Limestone Reservoirs with a Bottom Water Zone

An Investigation of Polymerflooding in Limestone Reservoirs with a Bottom Water Zone