Reservoir Underlain Research Articles

Calculation Method of the Phase Recovery of Gas Cap Reservoir with Bottom Water

In gas cap reservoirs underlain by bottom water, the connection between the reservoir and the aquifer leads to an increasing invasion of bottom water as reservoir development progresses. The average formation pressure of the reservoir will change, and the separated phase recovery of the gas cap reservoir with bottom water will be affected by the change in the average formation pressure. The traditional average formation pressure calculation formulas do not consider the water influx, so the accurate calculation of separated recovery cannot be obtained by those calculation methods. The development of gas cap reservoirs with bottom water presents several challenges, including the simultaneous production of oil and gas, undetermined rates of bottom water influx, and uncertain formation pressure and gas-to-oil ratios. These factors contribute to substantial discrepancies between theoretical calculations and actual observations. A more accurate and comprehensive approach is required to address these issues and enable a precise determination of the phase separated recovery in gas cap reservoirs with bottom water. The volume-deficit method is integrated with the Fetkovich quasi-steady state method for water influx. The water-influx prediction is incorporated into the material balance equation, which is further refined by introducing the Fetkovich model to enhance the estimation of the average formation pressure. The average formation pressure, once determined, is utilized in conjunction with the established relationships among this pressure, surface oil production, gas production, and the dissolved gas–oil ratio. Through the application of mass conservation principles, the varying degree of phase recovery, as influenced by fluctuations in the average formation pressure, is calculated. The precision of this refined method has been validated by a comparison with outcomes generated by simulation software. The results reveal a commendable accuracy: an error in the average formation pressure calculation is found to be merely 2.61%, while the errors in recovery degrees for gas cap gas, dissolved gas, and oil-rim oil are recorded at 2.73%, 2.94%, and 1.28%, respectively. These minor discrepancies indicate a good level of consistency and affirm the reliability of this advanced methodology, as demonstrated by passive assessments. This paper provides a method to accurately calculate the phase recovery without some oil- and gas-production data, which provides accurate data support for the actual production evaluation and subsequent development measures.

Strategizing well locations in unconfined, heterogeneous hydrate reservoirs for maximizing gas production

Natural gas hydrates are a potential alternative to conventional energy due to their high energy density and low carbon with wide distribution across the globe. Producing methane from the gas hydrate reservoirs is technically challenging as they are present in complex geological environments which are highly heterogeneous. In this work, using numerical reservoir simulations of gas production from oceanic gas-hydrate reservoirs underlain with an aquifer we show that warm-water injection is necessary when the water layer below the hydrates is unconfined. Our simulations reveal that the aquifer characterization is essential to design the gas production strategy and estimating the gas recovery. We demonstrate that for a gas-hydrate reservoir attached to a moderately unconfined aquifer, warm-water injection in the hydrate-zone leads to more recovery. If the hydrate-zone is layered then the gas recovery improves by injecting the water into a more porous layer. However, for highly unconfined reservoirs water should be injected near the aquifer for efficient recovery of gas. Our findings will help in developing gas production plans from the hydrate reservoirs around the world.

Well Placement Optimization through the Triple-Completion Gas and Downhole Water Sink-Assisted Gravity Drainage (TC-GDWS-AGD) EOR Process

Gas and downhole water sink-assisted gravity drainage (GDWS-AGD) is a new process of enhanced oil recovery (EOR) in oil reservoirs underlain by large bottom aquifers. The process is capital intensive as it requires the construction of dual-completed wells for oil production and water drainage and additional multiple vertical gas-injection wells. The costs could be substantially reduced by eliminating the gas-injection wells and using triple-completed multi-functional wells. These wells are dubbed triple-completion-GDWS-AGD (TC-GDWS-AGD). In this work, we design and optimize the TC-GDWS-AGD oil recovery process in a fictitious oil reservoir (Punq-S3) that emulates a real North Sea oil field. The design aims at maximum oil recovery using a minimum number of triple-completed wells with a gas-injection completion in the vertical section of the well, and two horizontal well sections—the upper section for producing oil (from above the oil/water contact) and the lower section for draining water below the oil/water contact. The three well completions are isolated with hydraulic packers and water is drained from below the oil–water contact using the electric submersible pump. Well placement is optimized using the particle swarm optimization (PSO) technique by considering only 1 or 2 TC-GDWS-AGD wells to maximize a 12-year oil recovery with a minimum volume of produced water. The best well placement was found by considering hundreds of possible well locations throughout the reservoir for the single-well and two-well scenarios. The results show 58% oil recovery and 0.28 water cut for the single-well scenario and 63.5% oil recovery and 0.45 water cut for the two-well scenario. Interestingly, the base-case scenario using two wells without the TC-GDWS-AGD process would give the smallest oil recovery of 55.5% and the largest 70% water cut. The study indicates that the TC-GDWS-AGD process could be more productive by reducing the number of wells and increasing recovery with less water production.

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.

Gas fields and large shallow seismogenic reverse faults are anticorrelated

We investigated the spatial relationships among 18 known seismogenic faults and 1651 wells drilled for gas exploitation in the main hydrocarbon province of northern-central Italy, a unique dataset worldwide. We adopted a GIS approach and a robust statistical technique, and found a significant anticorrelation between the location of productive wells and of the considered seismogenic faults, which are often overlain or encircled by unproductive wells. Our observations suggest that (a) earthquake ruptures encompassing much of the upper crust may cause gas to be lost to the atmosphere over geological time, and that (b) reservoirs underlain by smaller or aseismic faults are more likely to be intact. These findings, which are of inherently global relevance, have crucial implications for future hydrocarbon exploitation, for assessing the seismic–aseismic behaviour of large reverse faults, and for the public acceptance of underground energy and CO2 storage facilities—a pillar of future low carbon energy systems—in tectonically active areas.

Bayesian Calibration of a Natural State Geothermal Reservoir Model, Krafla, North Iceland

AbstractThe Krafla area in north Iceland hosts a high‐temperature geothermal system within a volcanic caldera. Temperature measurements from boreholes drilled for power generation reveal enigmatic contrasts throughout the drilled area. While wells in the western part of the production field indicate a 0.5–1 km thick near‐isothermal (∼210°C) liquid‐dominated reservoir underlain by a deeper boiling reservoir, wells in the east indicate boiling conditions extending from the surface to the maximum depth of drilled wells (∼2 km). Understanding these systematic temperature contrasts in terms of the subsurface permeability structure has remained challenging. Here, we present a new numerical model of the natural, pre‐exploitation state of the Krafla system, incorporating a new geologic/conceptual model and a version of TOUGH2 extending to supercritical conditions. The model shows how the characteristic temperature distribution results from structural partitioning of the system by a rift‐parallel eruptive fissure and an aquitard at the transition between deeper basement intrusions and high‐permeability extrusive volcanic rocks. As model calibration is performed using a Bayesian framework, the posterior results reveal significant uncertainty in the inferred permeability values for the different rock types, often exceeding two orders of magnitude. While the model shows how zones of single‐phase supercritical vapor develop above the deep intrusive heat source, more data from deep wells is needed to better constrain the extent and temperature of the deep supercritical zones. However, the model suggests the presence of a significant untapped resource at Krafla.

Effectively optimizing production of horizontal wells in homogeneous oil reservoirs

Horizontal well applications have been predominant since their conception, for reasons such as effective depletion of oil reservoirs and especially in water cresting, gas cresting or water and gas cresting applications due to the casings enhanced exposure to the reservoir. Cresting is hugely dependent on oil production rate, pressure drawdown and can negatively influence the degree of depletion as well as the overall recovery efficiency of oil reservoirs. This paper presents a novel procedure of mimicking horizontal wells aimed at investigating experimentally the effect of varying inclined sections (having different vertical and horizontal displacements) of horizontal wells at low angles of inclination (15°-30°) in a homogeneous reservoir underlain by a strong bottom aquifer and overlain by a considerable gas cap drive occurring simultaneously.The results for the performance of the different horizontal well geometries in terms of cumulative oil recovery and Water-Oil-Ratio; over a fixed liquid production time were compared. From the results obtained, it was observed that the short radius well with 30° angle of inclination and ratio of vertical displacement of the inclined section to reservoir height of 0.07 resulted in the highest oil recovery of 38.73%. Using the presented procedure, 5.60% increment in oil was recovered with 11.40% reduction in cumulative produced water were observed between the best and worst cases from the same reservoir. At higher withdrawal rates and pressure drop, long radii wells are recommended due to cresting delay ability while improving oil recovery.

Gas production from layered methane hydrate reservoirs

Reservoir simulations are used to find the production strategies for methane gas hydrate reservoirs. Most of these simulation models assume homogeneous reservoirs in absence of substantial well data. Many natural gas hydrate reservoirs are heterogeneous. Majority of the heterogeneity comes from the depositional layering at different geological time scales. Examples are Mount Elbert, block 818 in Gulf of Mexico, Walker Ridge 313 Site. The effect of cross-flow or no cross-flow between the layers is still unknown. In the present work, layered gas hydrate reservoir, underlain by a confined aquifer, with cross-flow between the layers is studied. A 3-dimensional, multi-component, multiphase, thermal, compositional simulator developed by Sun and Mohanty (2005) is used. Earlier work showed that for a confined, homogeneous reservoir underlain by an aquifer layer, depressurization method gives the highest recovery. So, in the present work, only depressurization of the reservoir is considered. In layered reservoirs recovery is found to be dependent on the total volume of the hydrate present in the reservoir, depressurization potential of the reservoir and the enthalpy available for dissociation irrespective of the layering. The layering suggests the positions and progress of the dissociation fronts.

Performance Analysis of Wells With Downhole Water Loop Installation for Water Coning Control

Summary Downhole water sink (DWS) technology controls bottomwater coning by draining water with a second completion placed under the oil-water contact. The technology has been studied theoretically with analytical, numerical and physical models, showing an increased rate of oil production and recovery. Also, improved wells? productivity with DWS has also been demonstrated in several field implementations. However, downhole drainage in DWS wells requires independent lifting of considerable volumes of water that necessitates using either two tubing strings (for water and for oil) or one tubing and the tubing/casing annulus--for water and oil, respectively. Also, extensive water drainage in the systems with weak bottomwater drive may cause a reservoir pressure drop and the need to return the produced water from the surface to the aquifer for pressure maintenance using designated injection wells. DWS well completion with the downhole water loop (DWL) offers the benefit of re-injecting the drainage water back to the same aquifer in the same well without lifting the water to the surface. This could be achieved by designing a DWS well with three completions: the top (oil) completion, the middle completion for water drainage and the bottom completion for water injection. Despite mechanical complexity of the triple well completion, there are two limitations of the DWL system--the drained-and-injected water must be free from oil and the pressure interference between the two water completions must be minimized. In this work, a well performance (nodal) analysis model has been developed for a DWL well completed in an oil reservoir underlain by water layer of known thickness. In the model, the positions (depths) of the three well completions and the rates of production and drainage/injection are design parameters, while all other properties are reservoir system properties. The model has been used to find the operational range of DWL for a given reservoir system and to compare DWL wells with conventional wells, single-completed at the top of the oil layer. The results show that for each DWL system, there is such a combination of the top production rate, bottom drainage-injection rate and drainage-injection distance (D/I spacing) that would result in water-free oil production. There is a minimum value of D/I spacing above which the detrimental effect of pressure interference between the two water completions is practically eliminated and the beneficial effect of water drainage on well performance is strong ? a two-fold increase of water drainage rate would increase the critical oil rate by 80%. Also, because the minimum D/I spacing is relatively small, DWL wells may be installed in reservoirs with thin layers of bottomwater.

Analytical solution for gas production from hydrate reservoirs underlain with free gas

Fast analytical models for predicting hydrate reservoir performance are very attractive, especially in the early phase of development of hydrate reservoirs when data are scarce and a large number of sensitivity studies are required. Recently, a number of analytical solutions have been developed that predict the rate of gas generation (and production) from hydrate-capped gas reservoirs. One of the simplifying assumptions of this research team's previous model – that the decomposition of hydrate is assumed to occur simultaneously throughout the hydrate zone – leads to optimistic results. To understand just how optimistic previous model's results may be, we present an alternative analytical solution that would lead to pessimistic results. Use of a previous optimistic model in conjunction with the current pessimistic one therefore provides bounding upper and lower limits of the rate of gas production from hydrate-capped gas reservoirs. The model presented here is developed by coupling the energy balance equation of 1D hydrate decomposition ahead of a moving interface with the material balance equation in a volumetric gas reservoir, and includes the thermodynamic relation of hydrate decomposition. Results are presented to show how this model may be used to estimate a lower bound for hydrate recovery and how these results depend on reservoir and hydrate properties.

Numerical simulation on gas production from a hydrate reservoir underlain by a free gas zone

Physical and mathematical models of gas production by depressurization from a hydrate reservoir underlain by a free gas zone are established. The mathematical model can interpret the effects of the flow of multiphase fluids, the process of hydrate dissociation, ice-water phase transition, the variation of permeability, the convection and conduction on hydrate dissociation and gas and water production. The evolutions of temperature, pressure, and saturations in the hydrate and free gas zones are elucidated during gas production. The variation of some parameters, such as gas and water rates, with time is presented. The results show that the overlying hydrate zone can supply a certain amount of gas to improve the output of a production well and evidently prolong the lifespan of a gas reservoir.

Basal Combustion-A Recovery Technology for Heavy Oil Reservoirs Underlain by Bottom Water

Abstract In Western Canada, many heavy oil reservoirs are underlain by thick bottom water. Very few of these reservoirs are commercially exploitable by conventional cold production or thermal technologies because of the high water mobility. The water zone could act as a strong water source that causes production wells to water-out quickly, or as strong energy sink that takes away most of the injected heat energy. As a result, these reservoirs are generally not attractive to produce, despite the enormous oil resources contained in them. Can the high mobility of water be beneficial to oil recovery? Can the known properties of bottom water (e.g., the oil-water contact, viscosity, density, and thermodynamic properties of water, etc.) be used as process tools to implement a successful recovery process? This paper attempts to address the above issues by introducing a new "Basal Combustion" concept that is built on the energy and mass transport characteristics of bottom water. Numerical simulation results indicated that, with the help of an effective transport and gathering system, a near level combustion surface could be initiated at the bottom of a heavy oil zone. The gas and water flows could serve as underground "conveyor belts" to deliver heat to the cold oil zone and, at the same time, remove mobilized and upgraded oils from the high temperature regions. High recovery and high energy efficiency can be expected. Introduction The Basal Combustion Process was conceived by not equating "bottom water" to "problems." Rather, the predictable features of bottom water were being sought after as tools for developing a new enhanced oil recovery technology. Specifically, the well known transport and thermodynamic properties of water were considered as potential assets for solving the mechanistic problems of in situ combustion. If the high predictability and reliability of heat and mass flows in bottom water could be translated into low operating risk, the injection of combustion air through bottom water would mean energy efficiency and profitability for in situ combustion. Observations from field operations and numerical simulation studies indicated that, when gas is injected into a bottom water heavy oil reservoir, most of it will flow along the upper part of the water zone and form a "basal gas layer" underneath the heavy oil zone. If oxygen is contained in the gas, this "basal gas layer" could become an extremely good in situ combustion site. The reasons are:the oxygen rich gas is in direct contact with hydrocarbon fuels, andonce ignited, this combustion layer will utilize a "heating from below" (or hot plate heating) mechanism to mobilize and upgrade the hydrocarbons above it. The potential benefits of basal combustion to heavy oil development in Alberta can be very significant. However, it would be risky to conduct field tests without a more concrete understanding of how this concept could be applied. Numerical simulation is therefore an effective method to obtain preliminary information for assessing the process feasibility, and for identifying needs for laboratory research work.

Sand Deposition Inside a Horizontal Well-A Simulation Approach

Abstract Horizontal wells have been shown to be successful in improving oil recovery for marginal heavy oil reservoirs in Saskatchewan and Alberta. One commonly encountered problem in recovery operations for these poorly consolidated reservoirs is the production of sand and fines into the horizontal wellbore, where they settle and accumulate. This paper reports the numerical modeling of gravitational deposition of sand in a horizontal well in such heavy oil reservoirs. The numerical model described in this work examines the transport process mechanistically, based on the conservation equations for the fluid phase (heavy oil) and the solid phase (sand particles). The interaction between these phases is described by empirical correlations. The equations are solved numerically to determine the concentration of sand particles and oil, and their respective pressure and velocity distributions inside the horizontal well. According to the simulation results, oil viscosity and particle size play important roles in the transport process, including controlling the gravitational settling tendency of solid particles inside the horizontal wellbore. The results provide insight into the roles different mechanisms affect the transport of sand particles; as such, they provide guidelines for production operations involving horizontal wells in poorly consolidated and unconsolidated reservoirs. Introduction The use of horizontal wells, in Saskatchewan and Alberta heavy oil reservoirs underlain with bottom-water, has been found to improve primary recovery performance prior to water coning-recovering up to 15%, in some cases, of the initial oil in place, compared with only 5% for a vertical well(1). Horizontal wells have also been successfully used for increasing steamflood recovery(2,3). Due to the unconsolidated or poorly consolidated nature of these reservoirs, solid (sand and fines) production is quite prevalent. The produced solids lead to several production problems, including sand filling up the wellbore, preventing the operation of downhole pumps and surface equipment, etc.(4) In horizontal well cases, sand production potentially poses a serious problem, as the sand could settle and accumulate inside the horizontal wellbore. This settlement and accumulation of sand particles could give rise to reduced cross-sectional areas of the wellbore open to flow. The study reported in this paper examines, using numerical simulation, the gravitational deposition of sand particles inside a horizontal wellbore. A brief survey of the relevant literature is given in the following. Solid-liquid multiphase flows are usually very complex, due to the large number of variables involved in the transport processes, and typically poorly understood interaction between the variables. There have been many experimental investigations of these (and other) flow processes, particularly focused on the deposition of the solid particles. Many of the earliest investigations of solid liquid flows focused on the settling tendency of solid particles. Richardson and Zaki(5) experimentally determined that the falling velocity of a suspension relative to a horizontal plane was equal to the upward velocity of the fluid required to maintain a suspension at the same concentration. For different flow regimes (i.e., Reynolds numbers), separate correlations were developed (from experimental data) for the exponent which corresponds to the slope of log-log plot straight lines between suspension falling velocities and suspension porosities.

Flow In a Constricted Horizontal Well

Abstract Horizontal wells have been used successfully in Canada to recover oil from marginal heavy oil reservoirs in Saskatchewan and Alberta. These reservoirs are often poorly consolidated; recovery operations in these reservoirs are, therefore, usually susceptible to sand production. A horizontal well could be partially blocked due to the deposition and accumulation of sand particles inside the wellbore. This study presents a mathematical treatment of the transport process of oil and sand particles inside a constricted horizontal well. The model described in this paper formulates the transport process mechanistically. Continuum assumption is made for the fluid phase (oil) as well as the solid phase (sand particles). Equations of mass and momentum conservation for the solid phase and the fluid phase are formulated. The oil is assumed to be Newtonian, and the sand particles are assumed to be spherical in shape and uniform in size. The model incorporates empirical correlations to describe the interaction between the two phases. The system of equations is solved numerically to determine the transient distribution of sand particles and oil, and their pressure and velocity distributions as a result of an expanding constriction inside the horizontal well. Numerical simulation results provided insight into the mechanisms involved in the transport process, thus enhancing the understanding of the flow of sand and oil inside a horizontal well. Introduction One of the most common applications of horizontal well technology in Canada is to recover oil from heavy oil reservoirs in Saskatchewan and Alberta. In heavy oil reservoirs underlain with bottom-water, the use of horizontal wells has been found to improve primary recovery performance prior to water coning, recovering up to 15% of the initial oil in place compared with only 5% for a vertical well(1). The recovery rate is also increased. Horizontal wells have also been successfully used for increasing steamflood recovery(2, 3). However, recovery operations in these heavy oil reservoirs are usually susceptible to sand production due to their unconsolidated nature. The produced sand could give rise to production problems, as the sand fill up the wellbore, prevent the operations of downhole pumps, etc.(4). In the case of horizontal wells, sand production potentially poses an even more serious problem, due to the settlement and accumulation of sand particles at different positions along the well, leading to the reduction of the cross-sectional area of the wellbore open to flow (Figure 1). The ultimate effect of sand deposition could be the partitioning of the horizontal well into several segments, leading to a loss of production and a negation of the principal advantage of horizontal wells (large contact area with the reservoir). The study reported here investigates this problem. Specifically the study examines, through numerical simulation, the transport and distribution of sand particles, and pressure, and velocity distributions in a horizontal well. A special feature of the model is the presence of a constriction inside the horizontal well.

Vapex: An Efficient Process for the Recovery of Heavy Oil and Bitumen

Summary The Vapex (vapor extraction) process may be a viable technique for the recovery of highly viscous heavy oil and bitumen. The size of the estimated heavy oil and tar sand resources in the United States amounts to 100 billion bbl and 62 billion bbl of oil in place (OIP), respectively. Although this represents a small fraction of the total world reserves, it is about one-third of the total estimated crude oil discovered in the United States. The world estimate of this resource is about 6 trillion bbl, six times the conventional oil reserves, and may be the future source of energy. Efficient extraction of these highly viscous crude oils poses a serious challenge to petroleum engineers. In some of the heavy oil reservoirs steam flooding and in-situ combustion processes were partially successful. For thick tar sand reservoirs, the steam-assisted gravity drainage (SAGD) process proved to be effective. However, thermal processes, in addition to other disadvantages, suffer from energy inefficiency caused by heat losses. The Vapex process involves injection of vaporized hydrocarbon solvents into heavy oil and bitumen reservoirs; the solvent-diluted oi1 drains by gravity to a horizontal production well. Recent research has shown that the process is highly energy efficient, environmentally friendly, causes in-situ upgrading, and requires low capital investment compared to its competitive process, SAGD. The applicability of the Vapex process may even surpass SAGD in thin reservoirs, reservoirs underlain by aquifer, offshore operations, etc. Some experimental results, a theoretical analysis, and the feasibility of this process for implementation in heavy oil and bitumen reservoirs will be presented.

Downhole Water Loop-A New Completion Method to Minimize Oil Well Production Watercut In Bottom-water-drive Reservoirs

Abstract Investigated in this study is a recently invented method to cut back the volume of formation water produced by an oil well from a hydrocarbon reservoir underlain by a water zone. The method involves initial completion of the well inside the water zone, below the oil-water contact (OWC) to install the water loop equipment, which is then separated by a packer from the conventional completion in the oil zone (above the OWC). Below the packer, the water loop installation includes a submersible pump, the upper perforations (water sink), and the lower perforations (water source). The submersible pump drains the formation water around the well from the water sink, and then reinjects the same water back to' the water zone through the distant water source perforations., In principle, the method should increase oil recovery with less (or no) formation water produced at the wellhead. Also, the method gives solution to the environmental problems associated with safe disposal of produced water. A simulation study was conducted to investigate the hydrodynamic performance of the method to restrain water movement towards oil-producing perforations. The downhole water loop was mathematically modelled using the flow potential distribution generated by two constant-rate sinks (oil and water) and one constant-rate source (water) located. between tne three linear boundaries and the constant-pressure outer radial boundary. The mathematical model was verified using data from studies on water coning. A good match was obtained when the distance between water source and water sink approached zero. The study reveals that the shape of the dynamic OWC in the well's vicinity can be effectively controlled by the method so that the oil production rates can be two- to four-fold higher than the critical rates obtained when using conventional completions. The method becomes increasingly effective when:the oil production by strong water drive is hindered by water coning;the bottom section of the well (in the water zone) is deviated so that the water source can be set below and aside from the water sink; andthe water zone is thick enough to allow sufficient lateral departure of the water loop without excessive curvature of the bottom section of the well. Introduction Several new concepts have been developed recently regarding concurrent and independent production of hydrocarbon and water in a single well. These new stimulation techniques derive from the principle that the local reduction of formation pressure would tender an increase in the well's productivity (1,8). In desorption-type gas reservoir, such as coalbeds and shales having a natural microfracturing system, the removal of water result in dewatering of the fracture system, higher gas saturation, and an increase in the relative permeability to gas. In water -drive oil reservoirs with water coning problems, the removal of water reduces the water flow potential field around the well so that the water come is kept down and below the oil producing performance.(2,8). Dewatering of coaled methane gas formation has been already successfully applied in field operation.

Recovery of Heavy And Conventional Oils From Pressure-depleted Reservoirs Using Horizontal Wells

Abstract Production of oil from reservoirs overlain by a gas cap causes the gas-oil interface to advance towards the producer and curve downwards. With conventional wells, the rate of production that is required for the operation to be economic is usually too high to avoid production of free gas. However, with horizontal wells, the critical production rate is higher and may allow economic operation without gas production. A stable interface can be maintained closer to the well giving much higher recoveries for comparable rates. Gravity stabilized, vertical gas displacement can also be utilized in reservoirs underlain by an active aquifer. In such operations, if the producer is kept at a potential equivalent to that of the aquifer, then free water production can also be avoided. The pressure is maintained by-the injection of the gas so that the oil is pushed out rather than sucked out. Equations relating the critical flow rate to maintain stability of the interface and the recovery are' developed in the paper and compared to experimental data from vertical Hele-Shaw models. The study examines the effect of production rate, well spacing, initial height of the reservoir and the type of fluid on the recovery for downward displacement of oil by gas to horizontal wells located at the base of the reservoir. Experiments have been carried out at conditions both above and below the critical rate. It is found that at very high rates the interface becomes unstable almost instantaneously and oil is displaced by a dominant finger of gas. At lower rates the interface is stable for most of the displacement and larger recoveries are obtained. More closely spaced wells and higher initial height of the reservoir give much better rates and recoveries. The agreement between the predictions and experimental data is good. Introduction There are many oil reservoirs in the world which have either an active water layer below the oil zone or a gas cap above it or both. Production of oil from such reservoirs causes the oil-water interface, or the gas-oil interface, to move towards the production well. The interface becomes curved and, with conventional wells, assumes a shape resembling that of a cone; this phenomenon is known as coning, either water coning or gas coning (Figure 1) or both. Coning, because it allows bypass of free gas or water, creates serious inefficiencies: loss of production, lower oil cut, poor sweep of the reservoir and lesser recovery of the oil in place. Mathematically, gas coning and water coning are analogous. Although this paper addresses gas coning, the ideas presented here are applicable to either case. FIGURE 1: Concept of coning. (Available in full paper) There exists a maximum rate, called the critical rate, for production of oil without bypass of free gas. This critical rate is usually too low to be economic. Horizontal wells offer an attractive alternative in some cases where conventional wells have poor performance due to coning problems. A horizontal well usually has a more extended contact with the reservoir than a vertical well.