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Collaborating Authors
SPE/DOE Improved Oil Recovery Symposium
Abstract Downhole oil-water separation (DOWS) provides the ability to conduct a cross-waterflood using a single wellbore that penetrates stacked waterflood zones. In this application of DOWS technology, production from one waterflooded zone is used as the inlet stream to the separation process. The oil-rich stream is produced to the surface while the water stream is injected into the second zone as shown in Fig.5. Potential benefits include reduced well count, reduced lifting costs, reduced expenditures for surface water handling facilities, reduced treating costs, smaller surface footprint and reduced environmental risk. Potential disadvantages include DOWS installation costs, more expensive workovers, more difficult and costly monitoring and larger wellbore requirements. DOWS technology is widely viewed as a potentially highly valuable technology with a high price tag and a high risk of failure. A major failure node for DOWS installation is the injection zone. Injection into a water flooded zone reduces the injectivity problems, and provides a benefit from the work required to inject the water stream. If a DOWS installation can economically be justified on its own merits anywhere, it will be in a cross-water flood application. The question remains; Can a DOWS cross-water flood be economically justified? This paper is divided in four parts. First, DOWS technology in general and cross-waterflood application in particular are briefly described. Second, the operational advantages and disadvantages of this application of DOWS technology are briefly discussed. Thirdly the parameters of economic model are reviewed in some detail. Lastly, the characteristics of a waterflood operation that can benefit economically from this technology are summarized. Introduction Many oil producing wells in the world are completed in stacked reservoirs where multiple producing formations are encountered. Such zones some times are also heavily supported by nearby aquifers. With time these wells produce water quantities to a level where they have to be either artificially lifted or abandoned due to high water lifting, treating, handling, and disposal costs. Often these volumes are in tens of thousands of barrels a day, which require great deal of effort and equipment in handling them. Large investments are done in artificial lift deployment in such wells to unload them. Such investments are unattractive in a sense that they do not provide additional production instead they are done to lift the water. Many times such multiple zones are marginal producers and are either not produced or delayed for the production when economic conditions allow produce them. These zones like any other waterflood candidate, may be considered for water injection. The timing of the waterflood project may play a crucial role in the production of such zones economically. To be specific, when the major producing zone in such a stacked reservoir is considered for water flooding, the marginal zone that would otherwise be plugged may also be considered as a candidate at the same time with a fraction of additional cost. This may also reduce the extra rig and labor costs that otherwise would be applicable if the zones are considered for waterflooding at different times. Many areas are either prohibited to oilfield water production and disposal activities, or may not be preferred due to environmental concerns. Such areas may be considered for this kind of application.
- North America > United States > Texas (0.47)
- North America > United States > Oklahoma (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
Abstract It is widely accepted that comprehensive data acquisition programs are necessary for WAG management and pilot project interpretations. Common data acquisition methods used to monitore WAG processes are frequently analysis of separator testing, fluid composition, production/injection rates, pressures injection surveys, gas-oil ratios (GOR) and saturation logging. Chemical tracers have been used as a tool for monitoring water and gas injection, whereas for WAG process no experience in a field has been reported in Latinamerica. At the Lagocinco field, C2/VLE-305 reservoir (located in Maracaibo Lake basin) a WAG pilot project is currently being developed, using a chemical tracers program with Perfluorocarbon and fluorinated Benzoic acids. Five chemical tracers have been injected in both phases (water and gas) during WAG test as a surveillance tool for the process. The aim to inject gas and water tracers was related to use breakthrough time and tracer production/injection history to get a better understanding of dynamic reservoir behavior and to support and upgrade the reservoir model. This paper briefly describes the monitoring process achieved in Lagocinco pilot project, and some results of this monitoring in relation to the WAG process. The result of the first water tracer test has indicated early breakthrough in four wells of the pilot project. One of the wells has increased oil production rate and three of them have maintained oil production rate and have decreased water cut and GOR as consequence of WAG process. The rest of the wells do not show a clear trend in tracer production, confirming heterogeneities in the pilot area. Zones not drained were identified and connection between the injector well and producer were characterized. The results of the first gas tracer have shown different distributions and velocities between gas and water. Finally, the second water tracer breakthrough was observed 3.3 months after its injection, just in one well, declaring that water distribution or path has changed as a consequence of WAG process. Introduction WAG injection processes have become an important IOR technique around the world [1], and have been focus of interest in recent years in Venezuela. This drained strategy is mainly planned to deal with the mayor concerns in Venezuelan oil fields: optimizing natural gas resources and increasing oil recovery factors [2]. Among several candidates, the VLE area was selected to evaluate an immiscible WAG process as representative of large number of deep (>10000 ft) light oil reservoirs in the Maracaibo Lake Basin with similar reservoir characteristics, currently under water injection at an advanced stage of depletion. In Venezuelan western reservoirs there are over 1.1 MMMSTB of oil currently in place in reservoirs with similar conditions. The selection of the VLE area as an Integrated Field Laboratory (IFL) [3] was based on screening criteria for WAG flooding, obtained from successful and unsuccessful worldwide projects [2], analytical simulation, experimental and numerical simulation studies, as well as availability of water and gas facilities. In this paper is described the first immiscible WAG injection pilot at VLE-305 in Maracaibo Lake focused on the monitoring process achieved with chemical tracers and productions curves. A better design, models and operational description of WAG process can be found in previous paper [4].
Abstract The Yufutsu gas-condensate field in Hokkaido, Japan, is an unusual reservoir. The fluid in the reservoir is heavier at the top, and the C7+ fraction decreases with depth despite pressure communication. Another unusual aspect of the reservoir is the decrease of the GOR from an initial value of around 1350 vol/vol to around 950 vol/vol in the first five years of production. In this work, we present the results of compositional simulation. The simulation is based on the initialization from a model that takes into account molecular, pressure, and thermal diffusion. The GOR predicted from the compositional simulation is in agreement with measured GOR. Introduction The Yufutsu field in Hokkaido, Japan, is a large gas-condensate reservoir. The reservoir is naturally fractured with a very tight matrix of granite/conglomerate rock of negligible porosity. The fractures provide both the storage and conductivity. The gas condensate is rich and has a high wax content. The field has an areal extent of 4 km × 8 km with a maximum hydrocarbon column of 1 km. Top of the reservoir is at 3800 m sub-sea level (mSSL). No distinct gas-water contact (GWC) or gas-oil contact (GOC) has been found. The Yufutsu field was discovered in 1989. A total of twelve wells have been drilled. Production started in February 1996. The initial reservoir pressure is about 550 bar and the temperature is 150° C at 4500 mSSL. Until early 2000, there was only one producer in the field (well MY1). Fig. 1 depicts the measured GOR produced from the well. This figure reveals that the GOR decreases gradually from around 1350 vol/vol to less than 1000 vol/vol. Under the same size bean, gas production has a decreasing trend while the condensate rate stays constant. The GOR from another well (MY2) which started producing in early 2000 shows a similar trend. The GOR decrease is believed to be due to the heavier fluid at the top of the formation at initial conditions (prior to depletion). In a previous work, we have studied compositional variation in the Yufutsu field. A new numerical algorithm based on a diffusion model from irreversible thermodynamics was developed to predict composition and pressure in the entire reservoir using a single PVT sample as a reference point. The results from the model were in good agreement with compositional data from different wells. It was demonstrated that thermal diffusion is the main phenomenon affecting compositional variation in the Yufutsu field. Due to thermal diffusion, a heavy fluid floats on the top of a light fluid. The model results also indicate the existence of liquid (in the near critical region) on the top of the vapor column in some upper part of the Yufutsu field. The predictions from the model are in agreement with pressure data from the shut-in wells tubing which show a high pressuregradient region between two low pressure-gradient regions. At the bottom of the tubing, the density is less than 400 kg/m; it gradually increases to over 500 kg/m in the middle; then there is a sharp density decrease to about 350 kg/m. A density of 500 kg/m corresponds to a liquid state while a density of 400 kg/m and less corresponds to a vapor state. The GOR decrease in the Yufutsu field is believed to be related to the state of initial fluid distribution: the liquid dropout at the top is higher than that in the bottom (see Fig. 2). Constantvolume depletion (CVD) data show that the retrograde-liquid dropout decreases substantially with depth. Data from some of the wells in the formation also show that the heavy fraction (C7+) decreases with depth. On the other hand, methane mole fraction increases with depth. The vertical compositional variation of heptane-plus in the Yufutsu formation is similar to that reported by Temeng et al. from the Ghawar Khuff reservoirs.
- Asia > Japan > Hokkaido Island (1.00)
- North America > United States > Texas > Dawson County (0.24)
- Asia > Japan > Hokkaido Island > Yufutsu Field (0.99)
- Asia > Middle East > Qatar > Block 4 > Khuff Field > Khuff Formation (0.98)
Geological Sequestration of Carbon Dioxide in a Depleted Oil Reservoir
Krumhansl, J. (Sandia National Laboratories) | Pawar, R. (Los Alamos National Laboratory) | Grigg, R. (Petroleum Recovery Research Center) | Westrich, H. (Sandia National Laboratories) | Warpinski, N. (Sandia National Laboratories) | Zhang, D. (Los Alamos National Laboratory) | Jove-Colon, C. (Sandia National Laboratories) | Lichtner, P. (Los Alamos National Laboratories) | Lorenz, J. (Sandia National Laboratories) | Svec, R. (Petroleum Recovery Research Center) | Stubbs, B. (Pecos Petroleum Engineering) | Cooper, S. (Sandia National Laboratories) | Bradley, C. (Los Alamos National Laboratory) | Rutledge, J. (Los Alamos National Laboratory) | Byrer, C. (National Energy Technology Laboratory)
Abstract Sequestration of carbon dioxide (CO2) in depleted oil reservoir is a strategy currently being considered to reduce the amount of CO2 in the atmosphere. However, a better understanding and prediction of the geologic processes that control CO2 injection in porous geologic media is necessary before depleted oil fields can become a safe and economical sequestration option. This paper provides new experimental and modeling results from a Department of Energy's (DOE) National Energy Technology Laboratory (NETL) sponsored CO2 sequestration project investigating these issues. Geologic modeling and numerical flow simulations are used to study the feasibility of injection into porous media. Interactions between injected CO2, reservoir fluids and reservoir rock are taken into account, including CO2 dissolution in water and water reaction with reservoir rock. These results are helping to design geophysical monitoring studies to track the injected plume. Laboratory tests and reaction path simulations were also used to investigate the fate of injected CO2 with reservoir fluids and minerals during extended static tests with reservoir core and brines. Results may help identify long-term geochemical processes that will affect sequestration. Introduction Carbon dioxide sequestration in geologic formations is the most direct carbon management strategy for long-term removal of anthropogenic CO2 from the atmosphere, and is likely to be needed for continuation of the US fossil fuel-based economy and high standard of living. Subsurface injection of CO2 into depleted oil reservoirs is a carbon sequestration strategy that might prove to be both cost effective and environmentally safe. In part, this is due to an extensive knowledge base about site-specific reservoir properties and subsurface gas-fluid-rock processes from the mining and petroleum industries, including those from recent Enhanced Oil Recovery (EOR) CO2 flooding activities. However, CO2 sequestration in oil reservoirs is a complex issue spanning a wide range of scientific, technological, economic, safety, and regulatory issues. Further detailed understandings of these interactions are necessary before this option can become a safe and economical sequestration option, and requires a more focused R&D effort by government and private industry. This paper provides an overview and update of our NETL-sponsored CO2 Sequestration project to predict and monitor the migration and ultimate fate of CO2 after being injected into a depleted oil reservoir. Details of the project and previous results have been published. The results of new simulations of oil-CO2-brine interactions and experiments of reservoir brine-core reactions are presented here. This project is a collaborative effort by Los Alamos National Laboratory, New Mexico Tech, Sandia National Laboratories, and Strata Production Company.
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract In-situ gelled acids are used in well stimulation to improve sweep efficiency during acid placement. These acids comprise a polymer, a cross-linker and a breaker in addition to chemicals used with regular acids. The gelation reaction in these systems occurs over a narrow range of pH (2–4). The gel forms once the acid reacts with the carbonate formation and the pH rises to a value above 2. The gel breaks once the pH rises above a value greater than 4. Propagation of the crosslinker plays a key role in the success of these acids. However, in a recent paper by Lynn and Nasr-El-Din, there was evidence of precipitation of the cross-linker in some systems. The cross-linker is typically a multi-valent cation (iron(III) or zirconium(IV)), which may precipitate at high pH values or react with hydrogen sulfide (in the case of sour wells) to precipitate damaging material. Coreflood experiments were conducted at 100°F in a linear mode to determine the rate of propagation of various cross-linkers in reservoir cores (mainly calcite). This temperature represents bottom hole temperature of seawater injectors in a carbonate reservoir in Saudi Arabia. Propagation of the cross-linker in carbonate cores was examined by measuring the concentration of the cross-linker in the core effluent and comparing it with the chloride ion concentration (used as a tracer). The profile of the tracer was used to determine dispersion of the acid in the core, whereas the area between the tracer and cross-linker profiles was used to determine the amount of cross-linker precipitated or retained in the core. The effects of acid concentration, slug volume, injection rate, cross-linker type, and polymer loading on the rate of propagation of the cross-linker were examined in detail. The following conclusions were made. 1. Viscous fingering effects that occur during pumping low-viscosity post-flush fluids affect the propagation of the cross-linker in reservoir cores. 2. The rate of propagation of the cross-linkers depends on the type of cross-linker used (iron, zirconium, etc.), and 3. Results of this study will help production engineers to design acid treatments with minimum damage due to precipitation/retention of the cross-linker. Introduction Hydrochloric acid (HCl) has been used to stimulate carbonate formations for more than seven decades. The acid, however, reacts very rapidly with the formation rock, especially at high temperatures. This in turn limits acid penetration into the formation, which can result in surface washout in matrix acidizing or poor etching patterns in acid frac treatments. In addition, straight or regular HCl acid has low viscosity, which can cause poor sweep efficiency during acid placement. Acid-soluble polymers (synthetic and biopolymers) have been used to increase the viscosity of HCl, and hence improve its performance. As the viscosity of the acid increases, the rate of acid spending decreases, and as a result, deeper acid penetration into the formation can be achieved. Addition of uncross-linked polymers to HCl improved acid penetration, however, acid placement was not significantly improved. Cross-linked acids were introduced in the mid 70's. These acids have much higher viscosity than regular acids or acids containing uncross-linked polymers. Two types of cross-linked acids are available. The first type consists of a polymer, a cross-linker, and other acid additives. The acid in this case is cross-linked on the surface and reaches the formation already cross-linked. The second type of crosslinked acid consists of a polymer, a cross-linker, a buffer, a breaker, and other acid additives, e.g., corrosion inhibitors and surfactants. The acid in this case reaches the formation uncross-linked, and the cross-linking reaction occurs in the formation.
- Asia > Middle East > Saudi Arabia (0.48)
- North America > United States > Texas (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract Injection of either carbon dioxide (CO2) or nitrogen (N2) can serve as an effective method for enhanced recovery of coalbed methane. In this paper, we provide new analytical solutions for flow of ternary gas mixtures. The adsorption/desorption of the components to/from the coalbed surface is approximated by an extended Langmuir isotherm, and the gas phase behavior is predicted by the Peng-Robinson EOS. Langmuir isotherm coefficients are used that represent a moist Fruitland coal sample from the San Juan Basin of Colorado. In these calculations, mobile liquid is not considered. Given constant initial and injection compositions, a self-similar solution that consists of continuous waves and shocks is found. Mixtures of CH4, CO2, and N2 are used to represent coalbed and injection gases. We provide examples for systems in which the initial gas has a high CH4 content, and binary mixtures of CO2 and N2 are injected. Injection of N2-CO2 mixtures rich in N2 leads to relatively fast initial recovery of CH4. Injection of mixtures rich in CO2 gives slower initial recovery, increases breakthrough time and decreases the injectant needed to sweep out the coalbed. The solutions presented indicate that a coalbed can be used to separate N2 and CO2 chromatographically at the same time CBM is recovered. Introduction Coalbeds have large internal surface area and strong affinity for certain gas species such as CH4 and CO2. In coalbed methane (CBM) reservoirs, most of the total gas exists in an adsorbed state at liquid-like density. Only a small amount of the total gas is in a free gas phase. Primary recovery using depressurization techniques induces desorption of the CBM by lowering the overall pressure of the reservoir. On the other hand, enhanced recovery of coalbed methane (ECBM) by injecting a second gas maintains overall reservoir pressure, while lowering the partial pressure of the CBM in the free gas. Injected gas also sweeps the desorbed gas through the CBM reservoir. Nitrogen is a natural choice as an injection gas because of its availability. Carbon dioxide, on the other hand, is also promising because of the additional benefit of greenhouse gas sequestration. When combusted, methane emits the least amount of CO2 per unit of energy released among all the fossil fuels. Therefore, synergy exists between CO2 sequestration and production of methane that leads to greater utilization of coalbed resources for both their sequestration ability and energy content. The first application of ECBM by CO2 injection has been carried out in the San Juan Basin, and proved to be technically and economically feasible. One important aspect of ECBM is the adsorption and desorption behavior of gas mixtures on coalbeds. A significant amount of work has been invested on this issue as it is related to coal mine safety. However, transport of the desorbed gas through coalbeds has not been examined in detail. Arri et al. studied the primary recovery of a single sorbing component and ECBM by nitrogen injection. In this paper, we extend the analysis to consider systems with three components. Besides CH4, coalbeds may contain significant amounts of CO2, N2 and other gas species. An average coal-bed gas is composed of approximately 93 percent CH4, 3 percent CO2, 3 percent wet gases, and 1 percent N2. Further, when flue gas, a primary source of greenhouse gases, is used for ECBM and CO2 sequestration purposes, the injection gas may contain more than two components. The exact composition of the flue gas depends on the combustion temperature and percentage excess air at different levels of moisture content in the fuel. In this study, we focus on the interaction of CH4, N2 and CO2.
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
Abstract In this paper, we present a methodology for predicting the propagation of acid along natural fracture networks and the resulting etching of the fracture walls as well as the skin factor of an acidized naturally-fractured well. The natural fracture network is modeled as a system of intersecting fractures that form a main pathway for acid transport and dissolution. The tails of the intersected fractures increase the leakoff from the main pathway and are accounted for in the model. The fracture network acidizing model is supported by comparisons with laboratory experiments and smaller scale simulations that determined the nature of acid channeling at fracture intersections. Model results illustrate the effects of variations in fracture properties on acid propagation. Prats' model is used to calculate the skin factor of an acidized, naturally-fractured well. The model predicts deeper acid penetration (up to 5 meters) under matrix conditions than would be possible with only matrix flow. Acid-etched fractures of this length result in skin factors of −2 to −3, similar to that observed in many carbonate acidizing treatments. Introduction Acidizing of natural fractures at matrix treating conditions differs from acid fracturing primarily because of the smaller fracture widths in the natural fractures. Our previous experimental study showed that acidizing small-width fractures results in three etching patterns in the fractures: channels, wormholes and surface etching. The etching pattern depends primarily on the fracture width and the surface roughness. We also developed a mathematical model of acidizing of carbonates containing a single natural fracture. The model simulated the flow and reaction of acid in rough-surfaced fractures, with acid transport to the fracture walls by diffusion and convection due to leakoff. The model predicted the same acid etching patterns with the same dependencies on fracture width and roughness as observed in the experiments. We first applied the model to predict the etching of long fractured cores (20 inch length) to compare with recent experiments. As with comparisons with our previous, shorter core experiments, the model predicted the general etching patterns observed. With typical natural fracture width (10–3 cm), we observed that acid usually creates a wormhole when far enough from the inlet. Increasing leakoff decreases the acid penetration distance and makes the channel broader. We then extended the single-fracture acidizing model to predict acid transport and rock dissolution in natural fracture networks surrounding a wellbore. We used Prats model to calculate the skin factor of an acidized naturally-fractured well, and developed a field-scaled design method for well treatments. Acidizing Fracture Networks Acidizing two intersected fractures. Since natural fractures generally occur in networks, we next extended our model to the acidizing process in fracture networks. Figure 1(a) is a schematic of the top view of a natural fracture network. When the acid is injected from a well, it first flows through the fracture segment from point A to point B and etches channels or wormholes. When the acid reaches the intersection at point B, it may flow into and create wormholes through both fractures, or may propagate primarily through only one fracture. Determining the acid behavior at the intersection of the fractures is important to best determine the acid flow and etching pattern in the entire fracture network. The geometry of the simulation in Fig. 1(b) represents three fractures that intersect with each other. The lengths and breadths of all fractures are 20 cm and 6.5 cm. Fracture 1 represents the fracture segment where the acid flows into the system, and fractures 2 and 3 are two intersected fractures. All fractures were generated with independent random data sets. This configuration represents an intersection point in the fracture network as in Fig. 1(a). Acidizing two intersected fractures. Since natural fractures generally occur in networks, we next extended our model to the acidizing process in fracture networks. Figure 1(a) is a schematic of the top view of a natural fracture network. When the acid is injected from a well, it first flows through the fracture segment from point A to point B and etches channels or wormholes. When the acid reaches the intersection at point B, it may flow into and create wormholes through both fractures, or may propagate primarily through only one fracture. Determining the acid behavior at the intersection of the fractures is important to best determine the acid flow and etching pattern in the entire fracture network. The geometry of the simulation in Fig. 1(b) represents three fractures that intersect with each other. The lengths and breadths of all fractures are 20 cm and 6.5 cm. Fracture 1 represents the fracture segment where the acid flows into the system, and fractures 2 and 3 are two intersected fractures. All fractures were generated with independent random data sets. This configuration represents an intersection point in the fracture network as in Fig. 1(a).
- Europe (0.69)
- North America > United States > Texas (0.69)
- North America > United States > California > Sacramento Basin > 3 Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/26a > Pelican Field (0.99)
Abstract As drilling and completion technology has advanced dramatically, developing new oil fields faces new opportunities of well structure selection, especially for the fields that are sensitive to issues such as environmental conservation, cost effectiveness, safety control, and well management. Horizontal, multi-branching and multilateral technologies have been used in many field applications all over the world to enhance the reservoir recovery in a cost-effective way. When the well structures become complex, producing from these "fancy wells" could become difficult, and sometimes, detrimental to overall recovery. To study the strategies for optimizing multilateral wells, we have developed a mathematical model to predict well performance for horizontal and multilateral wells using coupled multiphase models of wellbore/reservoir flow. The flow distribution along the laterals is predicted as a function of tubing head pressure (deliverability of the well), and overall well performance as a function of time is predicted by a simple material balance relationship. A common problem for such wells is that commingled production from multilateral branches can often lead to crossflow from one reservoir compartment to another. The likelihood of crossflow depends on initial reservoir conditions, but also very much on the operating conditions of the well. Deleterious interactions between commingled reservoirs accessed by multilateral wells must be reliably preventable for these types of completions to have broad application. Some case studies and hypothetical examples are presented in the paper to show the procedures for optimizing the well structure and well performance. Production strategies that would help to eliminate crossflow are discussed. Introduction To study the effect of crossflow in multilateral wells, we first developed a mathematical model to predict the flow distribution in the well system, which includes the flow profile along each lateral, the flow profile from each lateral, and the total flow rate, as functions of tubinghead pressure. The multilateral well deliverability model couples the calculations of inflow to each lateral, pressure drop behavior in each lateral, and pressure drop in the main wellbore. It finds the equilibrium producing point for commingled production in multilateral wells by iteration. Multilateral Well Deliverability Model The well geometry considered to develop the model is illustrated in Fig.1, using a trilateral well as an example. Each lateral is assumed to be horizontal and connected to the main wellbore with a build section. We also assume in the model that the build sections are non-producing and only provide paths between the horizontal producing sections and the main wellbore. Each lateral horizontal section, each build section, and the main wellbore can have different tubulars from one another. Pressure drops in the build sections and the main wellbore are calculated using a two-phase flow correlation.
Summary The Hunton Formation is one of the most promising formations producing oil and gas in Oklahoma. The formation has an anomalous producing behavior. At the inception, the wells produce at relatively high water-oil and gas-oil ratios. Eventually, both the WOR and GOR decrease. This results in increase in oil cut and hence reduction in lifting costs over time. Because of relatively high WOR's, many operators are discouraged from completing the wells, and hence abandoning the effort to produce oil from these formations. We concentrate on West Carney Field, Lincoln County, Oklahoma for this investigation. The field was "re-discovered" in 1995, and significant drilling activities continue in the field today. The field produces various amounts of gas, oil and water from each well. Because of varying gas oil ratios and water oil ratios over the field, a simple decline curve analysis is not applicable to determine the hydrocarbons in place. Attempts to calculate the reserves based on the electric log data have produced inconsistent results because of poor correlation between log signatures and productivity and connectivity of wells. In this study, we provide a technique for evaluating the performance of producing wells. Because the wells have variable rates and variable bottom hole pressures, we used the concept of equivalent time as proposed by Agarwal et al. (SPE 57916), and show that we can correctly predict the reserves estimate. Also, we show that it is possible, using Agarwal et al's equivalent time concept, to use automatic type curve matching to predict values of permeability and skin factor. We evaluate the gas, oil and water rates separately to calculate permeability and skin factor. We then use the results to estimate recovery factors and the quality of our initial completions. This type of analysis is useful for economic evaluation, planning of surface facilities, and future field development and exploitation. Further, if sufficient early production data are available, the procedure can also allow us to predict various reservoir parameters that can be used for additional evaluation. Introduction The West Carney Field initially produced very high water rates and low oil rates, but over time the WOR decreases providing for an increase in oil rate. The water rate slowly declines and eventually goes to zero in some cases. With high water rates come high lifting costs, so a good estimate of reserves is needed to determine the economic feasibility of the field. With this strange behavior, however, conventional methods for estimating reserves and reservoir parameters (permeability and skin) can no longer be calculated with confidence. A new production decline method is needed to accurately estimate reserves and reservoir parameters to adequately develop and exploit of the West Carney Field. Because the wells are produced at variable bottomhole pressures and variable rates, we have used an equivalent time approach presented by Agarwal et al. This paper, however, introduces the use of automatic type curve matching using the Levenberg-Marquardt algorithm. It will be shown, using synthetic data as well as one field example, that using Agarwal et al's equivalent time and nonlinear regression type curve matching can yield extremely useful results. The production for the three fluids is analyzed separately, allowing for reserve, permeability, and skin estimates for each of the three fluids.
- North America > United States > Oklahoma > Anadarko Basin > Carney Field (0.99)
- North America > United States > Texas > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- North America > United States > Oklahoma > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- North America > United States > Arkansas > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
Abstract The Lennox Field, located in the East Irish Sea basin UK, originally contained 184 mmstb of oil in-place within a 143 ft thick oil rim overlain by a large gas cap up to 750 ft thick. The GIIP is estimated to be 497 bcf. The oil and gas are trapped in the Triassic Ormskirk Sandstone Formation comprising high permeability aeolian and fluvial sandstone facies. The top reservoir occurs at a shallow depth (c.2500 ft) and contains a light, saturated oil (45° API) with a GOR of 650 scf/stb. The field came on stream in February 1996 and is now being developed with nine horizontal oil producers including four multi-laterals, and two crestal gas injectors. The total oil production to date (January 2002) is 43 mmstb. The current oil rim development phase will be followed by a gas cap blow-down phase anticipated to commence in 2004. Water cut from the field is currently around 2%, and some free gas production has been observed recently in a number of wells. Horizontal producing wells have been used exclusively, and the potential to improve oil recovery with multi-lateral wells was recognised from an early date. The challenge with this development is to manage voidage replacement whilst minimising early cusping of gas into the producing oil wells. Four wells have been drilled as multi-lateral producers (two being bi-lateral, one tri-lateral and one quad-lateral) at a depth of 3365 ft TVDSS, 35 ft above the oil-water contact. The first two multi-laterals were drilled with a vertical drilling tolerance of +/– 10 ft. This tolerance was reduced to +/– 2 ft in the two latest wells, L10 and L11, in order to minimise the chances of sumps being created along the wellpath. The decision to narrow the vertical corridor was based upon the operator's (BHPBilliton Petroleum) experience in the earlier wells where standing water was known to accumulate in sumps causing a reduction in well productivity. L10 was drilled as a quad-lateral horizontal infill well by successfully placing 4.5 km of 81/2 inch hole section within a +/– 2 ft corridor. In order to minimize the effect of inherent deviation survey errors the toe end of the horizontal well was placed 10 ft higher than its heel. The development of three open hole horizontal side-tracks using the Geo-Pilot rotary steerable system was a first in the industry. The well was completed in the last lateral leaving the first three laterals open. The objectives of the well L10 were to provide an additional oil producer to maintain plateau, to reduce the average producing GOR of the field, and to increase oil recovery. All of these objectives were fully met. The total horizontal reservoir section drilled was 14730 ft giving a total well Kh of 11.5million mD-ft over the producing section. The well is currently producing at around 22,000 bbl/d with a drawdown of 25 psi giving a well productivity index (PI) of 880 bbl/d/psi. The successful completion of the well enabled the operator to increase field reserves and to cut down production in other producers so that the overall field GOR has been reduced to manageable levels. Introduction History. The Lennox oil and gas field is situated in Blocks 110/15 and 110/14 of the East Irish Sea about 5 km from the coast in 40 ft of water (Fig. 1). Block 110/15 was awarded in 1991 with the current unit participants being BHP Billiton Petroleum Ltd (46.1%), Agip (UK) Ltd (45.0%) and Centrica plc (8.9%). History. The Lennox oil and gas field is situated in Blocks 110/15 and 110/14 of the East Irish Sea about 5 km from the coast in 40 ft of water (Fig. 1). Block 110/15 was awarded in 1991 with the current unit participants being BHP Billiton Petroleum Ltd (46.1%), Agip (UK) Ltd (45.0%) and Centrica plc (8.9%).
- North America > United States (1.00)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (1.00)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.91)
- Geophysics > Seismic Surveying (0.67)
- Geophysics > Borehole Geophysics (0.67)
- Europe > United Kingdom > Irish Sea > Irish Sea Basin (0.99)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Morecambe Bay > East Irish Sea Basin > Morecambe Bay > Block 110/8a > Morecambe Field (0.99)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Morecambe Bay > East Irish Sea Basin > Morecambe Bay > Block 110/7a > Morecambe Field (0.99)
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