Pressure Behavior Of Reservoirs Research Articles

Impact of Fault and Reef on Reservoir Pressure Behavior and Production Profile: Case Study- South Iraqi Oilfield

The study area, which consists of carbonate, is located in the unstable Mesopotamian basin on the Arabian plate, which makes it a field with high heterogeneity. It has a discrepancy in its bubble point pressure, which raises concerns about the faults or reefs that caused it. The study's main objective is to determine how faults and reefs impact production performance and pressure behavior under a future development strategy. This goal will be achieved by completing the necessary seismic, static, and dynamic models. After re-evaluating the seismic survey data, the seismic analysis detected many irregular amplitudes of reflected events and abrupt discontinuities, indicating either a reef or a fault. The static model was built based on seismic possible results and to make them as inputs for building the reservoir model. Based on the history-matching results, faults were detected, while reefs were ruled out. The development plan was implemented for the next 20 years in four cases, and case four had the most favorable results among all the cases, with production plateauing at 140 MSTB/D and a cumulative volume equal to 1.09 MMMSTB. The reservoir pressure behavior shows a hierarchical drop in all cases, with some differences, including a sharp decline in the area of the proposed wells and the fault, which has become a compartment that prevents reservoir compensation from adjacent regions.

Methods Used to Estimate Reservoir Pressure Performance: A Review

Reservoir pressure plays a significant role in all reservoir and production engineering studies. It is crucial to characterize petroleum reservoirs: by detecting fluid movement, computing oil in place, and calculating the recovery factor. Knowledge of reservoir pressure is essential for predicting future production rates, optimizing well performance, or planning enhanced oil recovery strategies. However, applying the methods to investigate reservoir pressure performance is challenging because reservoirs are large, complex systems with irregular geometries in subsurface formations with numerous uncertainties and limited information about the reservoir's structure and behavior. Furthermore, many computational techniques, both numerical and analytical, have been utilized to examine reservoir pressure performance. This paper summarizes the concepts and applications of traditional and novel ways to investigate reservoir pressure changes over time. It provides a comprehensive review that assists the reader in recognizing and distinguishing between various techniques for obtaining an accurate description of reservoir pressure behavior during production, such as the reservoir simulation method, material balance equation approach, time-lapse seismic data, and modern artificial intelligence methods. Thus, the central concept of these procedures and a list of the authors' research are discussed.

Numerical simulation of a nonlinear diffusion type equation in a two phase media with linear porosity and permeability model

Predicting and understanding the behavior of pressure is important in reservoir maintenance and evaluation. This work studies the behavior of fluid pressure in a reservoir by numerical simulation of the pressure diffusion type equation in a two phase media with a linear porosity and permeability model. Because the porosity and permeability are pressure dependent, the resulting diffusion type equation is nonlinear and is solved using a backward-forward finite difference method. The simulation code was ran using a constant porosity and permeability model and a linear porosity and permeability model. The results from the linear porosity and permeability model was compared to that of the constant porosity and permeability model. In both cases the pressure gradient was greatest at the wellbore and decreases as the radial distances away from the wellbore increases. The pressure in both cases also decreased with time. However, at each location and time the pressure drop was lower in the linear porosity and permeability model than with the constant porosity and permeability. The backward-forward finite difference method proved to be useful in solving numerically the nonlinear diffusion type equation. This work can be applied in the oil and gas industry to predict pressure behavior in reservoirs and make investment decisions, production and maintenance decision.

Prediction of reservoir pressure and study of its behavior in the development of oil fields based on the construction of multilevel multidimensional probabilistic-statistical models

Determination of the current reservoir pressure in oil production wells selection zones is an urgent task of field development monitoring. The main method for its determination is hydrodynamic studies under unsteady conditions. At the same time, the process of restoring bottomhole pressure to the value of reservoir pressure often lasts a significant period of time, which leads to long downtime of the fund and significant shortfalls in oil production. In addition, it seems rather difficult to compare reservoir pressures with each other in the wells due to the different timing of the studies, since it is impossible to simultaneously stop the entire fund for measuring the reservoir pressure in the field. The article proposes a new method for determining the current reservoir pressure in the extraction zones, based on the construction of multidimensional mathematical models based on the data of geological and technological development indicators. As the initial data, the values of reservoir pressure, determined during processing of the materials of hydrodynamic studies of wells, as well as a set of geological and technological indicators, probably affecting its value, were used (initial reservoir pressure for each well, the duration of its operation at the time of study, liquid rate, bottomhole pressure, the initial permeability and the current collector in the drainage area, GOR accumulated values oil, and liquid water, and skin factor). In the course of the research, several variants of statistical modeling were used, in the process of which the regularities of the reservoir pressure behavior during the development of reserves were established, individual for the object of development. The obtained models are characterized by a high degree of reliability and make it possible to determine the desired value with an error of no more than 1.0 MPa.

Seismic Performance Evaluation of Agricultural Reservoir Embankment through Shaking Table Tests

In this study, shaking table tests were performed to compare and analyze the acceleration response, displacement behavior, and pore-water pressure behavior of reservoirs with parapets installed to prevent overtopping of deteriorative homogeneous reservoirs. During the shaking table tests, the experimental conditions were divided into four cases considering the range and magnitude of seismic acceleration according to national standards. The vibration-type waveform (Gongen) and shock-type waveform (Minogawa) were applied as input waveforms. The acceleration amplification ratios of both vibration- and shock-wave types were the largest in the dam crest, and the amplification ratio decreased as the design earthquake acceleration increased. In addition, the horizontal displacement was maximum on the upstream slope, owing to the influence of seepage water, and the vertical displacement was maximum on the dam crest, owing to the self-weight effect of the parapet structure. A comparison of the waveform results indicates that the vibration-type waveform may exhibit a more significant effect on the embankment zone displacement than the shock-type waveform. However, when the safety standards for the horizontal displacement, settlement ratio, and excess pore-water pressure ratio were applied, the embankment was stable within the allowable range in both the shock-type and vibration-type waveforms. Therefore, the parapet structure is expected to influence the overflow resistance and stability of embankments positively.

CO2 dissolution and its impact on reservoir pressure behavior

Geological storage of CO2 in large, saline aquifers needs to be monitored for safety purposes. In particular the observation of the pressure behavior of a storage site is relevant for the indication of CO2 leakage. However, interpretation of observed pressure is not straightforward in these systems, due to the large number of natural processes that affects the pressure. These processes include pressure dissipation across aquifer boundaries for which both location and transmissibility are uncertain, pressure dissipation in low-permeable deposits surrounding the aquifer, dissolution of CO2 into the brine and chemical reactions. In this paper we will focus on the aquifer pressure effects of dissolution of CO2 in brine which can be significantly enhanced by density-driven convective mixing. The convective mixing occurs because the density of brine increases due to the dissolution of CO2, creating an unstable layer of dense brine below the CO2 plume. This layer may induce vertical, density-driven convective flow in so-called fingers. We have studied the effect of convectively-enhanced CO2 dissolution on the pressure in a CO2 storage site for 50 years using a volume balance model. This showed that only for reservoirs with very high permeability (>500mD in vertical direction) and a thin CO2 layer (<2–3m), the pressure reduction due to CO2 dissolution enhanced by convective mixing is important (>0.05bar/yr). For most examples simulated here, the effect of CO2 dissolution on the pressure was minor (<0.02bar/yr or <0.2% of the pressure increase due to CO2 injection per year).

Transient Pressure Behavior of Reservoirs with Discrete Conductive Faults and Fractures

Fractures and faults are common features of many well-known reservoirs. They create traps, serve as conduits to oil and gas migration, and can behave as barriers or baffles to fluid flow. Naturally fractured reservoirs consist of fractures in igneous, metamorphic, sedimentary rocks (matrix), and formations. In most sedimentary formations both fractures and matrix contribute to flow and storage, but in igneous and metamorphic rocks only fractures contribute to flow and storage, and the matrix has almost zero permeability and porosity. In this study, we present a mesh-free semianalytical solution for pressure transient behavior in a 2D infinite reservoir containing a network of discrete and/or connected finite- and infinite-conductivity fractures. The proposed solution methodology is based on an analytical-element method and thus can be easily extended to incorporate other reservoir features such as sealing or leaky faults, domains with altered petrophysical properties (for example, fluid permeability or reservoir porosity), and complicated reservoir boundaries. It is shown that the pressure behavior of discretely fractured reservoirs is considerably different from the well-known Warren and Root dual-porosity reservoir model behavior. The pressure behavior of discretely fractured reservoirs shows many different flow regimes depending on fracture distribution, its intensity and conductivity. In some cases, they also exhibit a dual-porosity reservoir model behavior.

Numerical modeling including hysteresis properties for CO2 storage in Tubåen formation, Snøhvit field, Barents Sea

Abstract In April 2008 the first injection of supercritical CO 2 started into the Tubaen Formation from the Snohvit field, Barents Sea. At full capacity, the plan is to inject approximately 23 Mtons of CO 2 via one well during a 30 year period. The aim of this study was to simulation the 30 years of injection of supercritical CO 2 and the following long term (5000 years) storage of CO 2 in the Tubaen formation. The formation is at approximately 2600 meters depth and is at 98 °C and 265 bars. The simulations suggested that, because of limited lateral permeability, the bottom hole pressure increases rapidly to more than 800 bars if an annual injection rate of 766000 tons is used. This is significantly higher than the fracture pressures for the formation, and it is therefore suggested that the aim to inject 23 Mtons over the planed 30 years may be unrealistic. To prevent fracturing due to increasing pressure, the bottom hole pressure constraint is applied that leads to significant decrease in the amount of CO 2 injected. With the hysteresis property applied, reservoir pressure behavior is the same in the base case (no hysteresis); however, the CO 2 plume is distributed over a smaller area than in the base case. Similar to the case of hysteresis, the diffusion flow case shows the CO 2 plume to be distributed over a smaller area than in the base case, but reservoir pressure decreases more than in the other two cases.

New Results on Transient Well Tests Analysis Considering Nonlaminar Flow in the Reservoir

Summary The aim of this work is to examine the wellbore pressure behavior in reservoirs with single-phase non-Darcy flow conditions produced at a constant sandface rate. The transient flow period is analyzed by means of results generated with a finite difference model. Analytical expressions of pressure drop and its semilogarithmic slope are presented for the first time. These equations contain the laminar flow solution as a particular case, and they provide means to evaluate the total skin factor. Another use of the analytical solution to the non-Darcy flow problem is to identify the presence of inertial effects by using a diagnostic plot, which consists of graphing the derivative of the pressure data vs. the inverse of the square root of time on a Cartesian paper. In this way, an analyst easily can predict the magnitude of the skin owing to nonlaminar flow under any condition of mechanical skin and rate. Furthermore, better stimulation jobs can be designed if non-Darcy flow conditions during a transient test are properly identified through the methodology presented in this study. The use of the methodology obtained in this work is illustrated with synthetic examples for homogeneous and naturally fractured reservoirs. Also, a field example of an undersaturated reservoir and a dry gas case (taken from the literature) shows the application of this technique. For the case of naturally fractured reservoirs, new insights are provided.

Integration of Outcrop and Subsurface Fracture Data for Reservoir Modeling of the Natih Field, North Oman

The Natih field reservoir comprises several distinct fractured limestone intervals which contain some 500 {times} 10{sup 6} m{sup 3} STOIIP. The field is being developed by gas-oil gravity drainage. Fracture orientations, dimensions, and spacings are critical to predict the effectiveness of this process. Statistically representative fracture data from Cretaceous Natih outcrop analogs in North Oman, core data, and electrical borehole imagery provided a realistic input for Natih field reservoir modeling and simulation. In the outcrops the fractures trend both cross-axially and longitudinally with dimensions and spacings varying with lithology, bed thickness, and curvature. Dimensions of matrix blocks in clean thickly bedded limestones are an order of magnitude greater than in more argillaceous thinly bedded limestones. Subsurface data from the Natih reservoirs indicate that open cross-axial subvertical northeast-southwest-trending fractures dominate and strongly influence the reservoir flow pattern, but longitudinal fractures could not be identified. This is in line with the orientation of the present day, principal horizontal in situ stress that preferentially keeps open the cross-axial fracture set. Fracture apertures from borehole imagery have a range of 0.1 to 0.3 mm which is consistent with that derived from reservoir pressure behavior. Combining outcrop and well data results in a Natih reservoirmore » fracture model with open cross-axial fractures that have a lithology dependent spacing of 0.1 to 2 m over the entire structure. From these data fracture porosities are calculated for each gridblock in the model. Longitudinal fractures probably exist in the vicinity of faults and in the northern part of the field where rapid down-warping occurs.« less

Pressure Transients Characterize Fractured Midale Unit

Summary The Midale Unit is a naturally fractured carbonate reservoir in the Williston basin of southeastern Saskatchewan. Recently, the Midale working-interest owners initiated a CO2-flood pilot project with several closely spaced wells. A comprehensive interwell pressure-transient test program was conducted for reservoir-characterization purposes before pilot program was conducted for reservoir-characterization purposes before pilot operations began. The combination of conventional, pulse, and interference tests resulted in a detailed local description of this naturally fractured reservoir. Selected pressure-transient data from the reservoir-characterization program are presented. The data dramatically illustrate the program are presented. The data dramatically illustrate the pressure-transient characteristics of an anisotropic, naturally fractured pressure-transient characteristics of an anisotropic, naturally fractured reservoir. Analytical techniques are reviewed briefly, and an interpretation technique for multiwell pressure-transient tests in wells with negative skins is included. A discussion of the pressure-transient behavior that is observed in wells with typical field spacing is also included. Introduction A significant proportion of the world's oil reserves exists in naturally fractured rocks. As a result, the pressure-transient behavior of naturally fractured reservoirs has been studied widely. These reservoirs, referred to as dual-porosity or dual-permeability systems, can be modeled with matrix blocks of various shapes separated by continuous fracture networks. Typically, the system permeability is largely associated with the fractures, while the tighter matrix contains most of the reservoir-storage volume and acts as a fluid source for the fracture network. Initial production from dual-porosity reservoirs is from the more permeable fracture network, which results permeable fracture network, which results in pressure decline in the fractures. Depletion of the fracture system causes pressure gradients to develop between the matrix blocks and the fractures, which results in fluid flow from the blocks into the fractures. This transitional flow period controls the reservoir-pressure behavior until the matrix fracture pressure regime equilibrates, after which the reservoir acts as a uniform system with composite properties. Pressure-transient testing is an important technique used to describe naturally fractured reservoirs. Each flow period (fractures, transitional, and composite) has distinctive pressure-transient characteristics. Pressure-transient behavior in real Pressure-transient behavior in real dual-porosity reservoirs, however, can be subtle and ambiguous, especially in normal situations with typical well spacing. For example, pressure transients controlled by depletion of the fracture network are rarely seen in the field because of the fast onset of the transitional flow period. Transitional- and composite-system pressure transients can be attributed to such other causes as layers, skin, faults, or boundaries. Wellbore storage can obscure key parts of the pressure-transient curve. For these and other pressure-transient curve. For these and other reasons, few comprehensive pressure-transient data bases exist for naturally fractured reservoirs. The scarcity of good data impedes refinement and validation of precise pressure-transient models. The Midale field (Fig. 1) produces oil from relatively tight, naturally fractured carbonates. The field was discovered in 1953 and produced competitively under primary depletion until unitization for waterflooding in 1962. Secondary performance is dominated fieldwide by the oriented-fracture system, which causes a permeability anisotropy of about 25:1. Recent implementation of a tertiary miscible CO2-flood pilot project in the Midale Unit, with 10 wells on 4.4 acres [1.8 ha], has allowed for very detailed reservoir characterization. Conditions in the Midale CO2-flood pilot are amenable to both single- and multiwell pressure-transient programs. An extensive, precise pressure programs. An extensive, precise pressure transient data base was acquired during pilot-testing operations. The reservoir pilot-testing operations. The reservoir model that was obtained from pressure-transient analyses is consistent with geological, petrophysical, and operational data, and it petrophysical, and operational data, and it provides significant refinement over earlier provides significant refinement over earlier reservoir models.

Pressure Buildup Analysis of Geothermal Steam Wells With a Parallelepiped Model

Summary Geothermal well testing, a discipline that evolved from conventional oil and gas well testing, often requires special considerations. The geometry of the reservoir and those characteristics frequently found in geothermal systems engendered the idea of a parallelepiped model with interpenetrating fractures. Such geometry can be described mathematically using Green's and source functions. Equations of reservoir pressure behavior then can be developed for both drawdown and buildup tests. Graphs describing dimensionless pressure as a function of time and various reservoir parameters are provided in this paper. The general method used is type-curve matching. Introduction There are three major types of geothermal resources:(vapor-dominated (dry-steam) such as in The Geysers (CA) or in Tuscany of central Italy,two-phase such as in New Zealand, andhot-water, found in several locations. The most useful, in terms of power production, are the vapor-dominated reservoirs. They are also the most rare. A number of geothermal reservoirs exhibit transient pressure behavior that indicates large, highly conductive fractures. The size of these reservoirs is controlled by faults and overlying impermeable rocks. A constant-pressure boundary, presumably boiling water, often is observed. A parallelepiped model conceptually could approximate such a configuration. A model with closed, no-flow boundaries on five sides and a constant-pressure boundary on the bottom was described by Cinco-Ley et al. The fracture system was simulated as a rectangular-shaped source. The concept is limited to vapor-dominated reservoirs. Both geologic evidence and production histories have precluded the use of radial models in both The Geysers and Larderello, Italy. Hence, the parallelepiped model, with the included fracture and subformation boiling front, is intended to analyze pressure transient behavior in dry-steam geothermal wells. Model Description The model assumes constant-flow-rate production in an anisotropic, homogeneous reservoir. If the flow rate vases, an influence function such as that described by Economides et al. can be used in the subsequent type-curve matching. The reservoir described by the model contains a slightly compressible fluid of constant viscosity and compressibility c. an assumption totally inadequate in the case of geothermal steam. Yet the shortcomings can be overcome if the pseudopressure function m(p) is used. The real-gas pseudopressure was discussed by Al-Hussainy and Ramey. All of these assumptions normally are used in geothermal well testing, irrespective of the model. Although the solution can be modified to incorporate fracture(s) anywhere in the reservoir, a vertical, partially penetrating fracture has been used. The fracture is in the center of a parallelepiped reservoir of square horizontal cross section. JPT P. 925^

Recovery of Energy From Fracture-Stimulated Geothermal Reservoirs

Energy recovery by in-place boiling was studied with a laboratory to model, of a fracture-stimulated geothermal reservoir that can be heated to 500 deg. F and to a pressure of 800 psig. An analytical mode to evaluate rock-energy extraction was developed and agreement between predicted results and experimental results was satisfactory. Introduction Geothermal resources used for electric power generation are hydrothermal systems that exist either as vapor- or liquid-dominated reservoirs. Although the latter type is believed to be more abundant, the extent of hydrothermal resources is considered small compared with hot, igneous rock resources that. do not spontaneously produce steam or hot water because of a lack of permeability, porosity, and fluid storage. Economic development of geothermal resources will require advanced technologies for enhanced recovery of energy from hydrothermal reservoirs and the introduction of artificial circulation systems for extracting energy from hot, igneous rock. Several fracture-stimulation techniques have been proposed, such as explosive fracturing, hydraulic fracturing, and thermal stress cracking. Smith et al. described a large-scale hydraulic fracturing experiment in hot, igneous rock where a closed circulation loop of surface water under high pressure is used to extract the thermal energy by convective heat transfer. A variation of that extraction scheme using multiple fractures was proposed by Grinparten and Witherspoon . Stimulation of geothermal reservoir by nuclear explosive fracturing was proposed by Carlson and Kennedy. Nuclear explosive stimulation of natural gas reservoirs has been demonstrated successfully on an experimental basis . Explosive stimulation of hydrothermal systems was discussed by Ramey et al. They showed that the total energy in a hydrothermal system consists of tie thermal energy stored in the rock and the thermal energy stored in the geothermal fluids. The ratio of the magnitudes of these two components depends principally on the rock porosity. Ramey et (11. also demonstrated that the amount of energy extractable from a hydrothermal system can be enhanced by operating the system nonisothermally (for example, by pressure reduction) so that boiling (flashing) takes place within the rock formation. Nonisothermal heat-transfer processes in fractured rock systems have not been studied experimentally. However, several laboratory experiments on nonisothermal flow in porous media have been conducted. The studies described in this paper were designed to explore(1) conditions for optimum energy extraction, (2) rock heat-transfer characteristics, (3) moving flash fronts, (4) fluid-withdrawal reservoir pressure behavior. (5) effects of cool and hot fluid recharge, and (6) cyclic production/recharge operation of fracture-stimulated production/recharge operation of fracture-stimulated systems. The experiments were carried out in a laboratory model using rock loadings with characteristics that resemble the highly fractured region of a fracture-stimulated hydrothermal reservoir. Experiments were conducted with two rock loadings of different porosities and mean rock sizes at pressures and temperatures found in geothermal reservoirs. The extent of fluid recharge was limited so that energy addition by fluid recharge was less than the energy extracted from the rock. Preliminary evaluations of the results were reported by Hunsbedt et al. and detailed results were reported by Hunsbedt. This paper highlights these results. JPT P. 940

Reservoir Evaluation and Deliverability Study, Bierwang Field, West Germany

To determine an optimum production strategy, an areal two-dimensional gas-water model, cross-sectional studies, and a coning model were used. history match showed appreciable horizontal water influx. Water coning, however, would not be a problem, and channeling could be overcome by additional perforating. Ultimate gas recovery can be considerably increased if withdrawal rates are kept high. Introduction Until imported gas is available in Bavaria, the present measure for filling the gap between present measure for filling the gap between increasing gas demand and diminishing gas reserves is to accelerate the gas recovery from existing fields. The dominant role of the Bierwang field is illustrated by the fact that in 1971 this field produced 28 Bcf of gas, or 59 percent of be total produced 28 Bcf of gas, or 59 percent of be total natural gas production of Bavaria. The field (Fig. 1) was discovered in 1964 with the drilling of Bierwang C2, which encountered several gas-bearing horizons. With respect to gas in place, the most interesting zone was the Chattian Main Sand, consisting of a well developed porous sandstone with a 105-ft hydrocarbon section. The Chattian Main Sand reservoir is a stratigraphic, structural trap with a porosity pinch-out due to an erosional pinch-out on the eastern edge and an impermeable fault boundary to the north and west. The downdip limit, to the south, is defined as a gas-water interface at 3,428 ft subsea. The original gas in place, determined dynamically and volumetrically, was about 156 Bcf. The gas is both sweet and dry, permitting this reservoir to be studied as a dry gas pool permitting this reservoir to be studied as a dry gas pool with an aquifer. The size and extent of the aquifer are not known reliably. However, the reservoir pressure behavior indicates the existence of a strong water drive with associated water influx. To the end of 1970, five wells were capable of gas production. However, one of these wells had exhibited water breakthrough and was producing with a continually increasing water cut. The objectives of this study were to determine the came of Ne water production, to predict the future deliverability of the reservoir, and to determine the expected ultimate gas recovery. The study was performed in three stages. The first part was a pressure history match of the reservoir performance to determine the extent of the aquifer influx and to confirm the estimate of original gas in place by material balance. The second stage was an investigation of all possible causes of water production. The third stage consisted of future deliverability studies to investigate pool capability to meet the gas demand and finally to determine the ultimate gas recovery resulting from an optimum development strategy. Reservoir Pressure History Match The Bierwang field was discovered in 1964, and sustained gas production began in mid-1967. (Fig. 2 shows the production history of the pool.) Annual pressure surveys have been conducted in the pool pressure surveys have been conducted in the pool since 1967. Individual well pressure history is available for the five producing wells and is given in Table 1. The pressures decline at a decreasing rate with cumulative production, revealing the existence of a water drive from the adjoining aquifer. JPT P. 23