Gas Cap Reservoir 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.

Neutron Response Modeling to Track Lean Gas Plume in Recycled Gas Cap Reservoir in Concurrent Gas Cap-Oil Rim Development: A Step Forward

Summary Gas cap pressure maintenance while developing the associated oil rim is a critical aspect for optimum recovery. Preventing gas cap pressure dropping below dewpoint by injecting lean gas is essential for concurrent gas cap-oil rim development. Reservoir heterogeneity aggravates lean gas override causing preferential movement of lean gas plume. Thus, it is important to track lean gas plume while recycling and understanding the breakthrough potential of lean gas. This paper demonstrates a new workflow to track lean gas plume by estimating phase saturations with a case study from one of the giant oil and gas fields, Onshore, Abu Dhabi. Pulsed neutron capture (PNC) tools are used for reservoir monitoring and surveillance. However, sigma log evaluation is insufficient to derive individual hydrocarbon phase saturations to monitor lean gas plume. Neutron response modeling (NRM) is devised to differentiate between lean and rich gas. NRM is a probabilistic solver with input of mineral and fluid phase parameters into tool response functions in petrophysical evaluation. To distinguish with discrete neutron fluid response between lean and rich gas, pressure/volume/temperature (PVT) data are utilized to derive hydrogen index, capture cross section, thermal decay length, and neutron macro parameters, such as neutron slowing down length and migration length. Neutron response is investigated for lean and rich gas with sensitivity of invasion effects on neutron log by calibrating to core porosity. The response for each phase under thermal neutron and capture modes with corresponding raw neutron log statistics is reviewed in both openhole and casedhole environments in known lean/rich gas intervals. Thirty-five wells spread across gas cap and oil leg with quality neutron log data are modeled and individual phase saturations are estimated. The target reservoir is under development with over three decades of lean gas injection to support oil production. NRM results and phase saturations are validated with recent formation sampling, which enhanced the confidence in the overall workflow. Later, the results are verified to be in excellent agreement with lean gas injection and production history of the target reservoir. The identified movement of lean gas highlights nonuniform geology and gravity segregation of injected lean gas into upper members of the target reservoir. The results also emphasized the need for better injection support to lower members of the target reservoir where gas cap development is ongoing. The solution presented is unique, particularly for lean gas injection projects by utilizing PVT for NRM based on neutron transport mechanism in pore fluids. Existing workflows require a special nuclear modeling platform with computationally expensive processing on data sets acquired using advanced logging technology. In spite of these prerequisites, existing workflows are not able to distinguish lean gas over rich gas. This paper effectively demonstrates NRM workflow distinguishing lean gas plume from rich gas using neutron logs and reveals compelling reservoir management insights. The sensitivity studies and practicality of this workflow highlight the fundamental importance of neutron logs in mature fields.

Prediction of gas coning in hydrocarbon reservoir using tNavigator

Several approaches for avoiding gas breakthrough due to coning phenomena have been proposed. These methods include maintaining oil production rates below critical rates, inserting crosslinking gels near the well to create a gas-blocking area, and making perforation as far away from the initial gas-oil contact (GOC) as possible, often considered uneconomically solutions and not sufficient way to deal with the problem. Furthermore, this is a major source of concern in terms of the additional costs of separation procedures and equipment availability. Coning couldn’t possibly be totally eliminated, but it can be minimized by defining the breakthrough time and understanding the characteristics that have a significant impact on breakthrough time and how effectively may be manipulated to delay it. A mathematical and numerical approach was used in this research for the purpose of gas breakthrough time investigation and monitoring the gas-oil ratio (GOR). tNavigator embedded flow equation was used as a novel 3D compositional simulation principle in the software to predict the time of gas flow from grid cell to another reaching the perforation interval, for the purpose of utilizing the sensitivity analysis of certain parameters which had sufficient impact on GOR value and breakthrough time (tBt). Results show that the Oil column is the most effective parameter in the sensitivity analysis and the one factor to focus on while producing from gas cap reservoirs.

Application of monitoring method in the establishment and maintenance of gas cap injection barrier in a Oilfield

In order to make technical reserves for developing gas cap and buffer zone in A Oilfield and explore effective development methods of gas cap reservoir, according to the overall development idea of oil-gas ring, a field test of gas cap injection and polymer barrier development buffer zone in Layer B was carried out in the structural axis of South Block in 2006. The test adopted the development mode of gas cap injection and polymer barrier development buffer zone, that is, the barrier was established by injecting polymer solution at the oil-gas boundary to separate natural gas from crude oil in buffer zone and keep relatively stable. In this paper, the morphological changes during the establishment and maintenance of barriers are found out by means of monitoring.

WITHDRAWN: Integrated approach of fluid modeling using material balance technique to estimate oil in place, case study: Northern IRAQ

Approximating hydrocarbons in place is one of the significant duties of the reservoir engineering. In this study, the reserve calculation is carried using Material Balance Technique utilizing MBAL software and a special Excel workbook donated as RUN. The RUN is a visual basic based excel workbook, it programmed to apply material balance for gas cap reservoir to estimate the Oil initially in place (OIIP) based on the saturated oil reservoir equation.a straight line utilized to estimate the initial oil based on Havlena and Odeh modified method as a replacement for of the Material Balance Equation (MBE). Field production data, PVT and reservoir pressure history were arranged as input to the material balance equation. The results compared the calculation of the initial oil in place concluded from preceding studies. The OIIP RUN results were 1237.3 MMSTB and 1245.66 MMSTB from MBAL software using. The value of 1226 MMSTB was in strong agreement with previous research focused on the volumetric approach in the geological model.

Study on the Critical Production Calculation Method of the Water-Flooding Reservoir with Gas Cap

The aim of this paper is to solve the problems that the existing method of critical production of gas cap reservoir is only suitable for single-phase flow, and the method of critical production of gas cap reservoir under water-flooding is still blank. In this paper, the relationships between dynamic and static equilibrium, plane radial flow theory, oil-water infiltration method and three-dimensional seepage field decomposition theory, were applied to study a calculation method for critical production of directional wells and horizontal wells. Furthermore, the effects of different factors on critical output were studied, such as horizontal permeability, ratio of horizontal permeability to vertical permeability, length of horizontal section, effective thickness, viscosity of crude oil and water content etc. Results show that the critical production increases with the increment of the horizontal permeability, the ratio of the vertical permeability to the horizontal permeability, the reservoir thickness and the horizontal well length; when the viscosity of crude oil is small, the critical production decreases first and then increases with the increase of water content; when the viscosity of crude oil is high, the critical production increases continuously with the increase of water content. This study could provide theoretical and technical guidance for changing of the working system of oil wells. It can avoid gas channeling and improve the development effect.

Technique Policy for Concurrent Development of Gas Cap and Oil Rim of Gas Cap Reservoir

For the A South and Γ North reservoir of Zhanzhol oil field in Kazakhstan, only the oil rim was developed since 1983. Recently, the gas cap of A South reservoir was exploited in September, 2014. However, the concurrent production of gas cap and oil rim is likely to cause the pressure imbalance, which will lead to the worse development effect of the whole reservoir. In order to acquire the efficient concurrent production of gas cap and oil rim, the technique policy charts of concurrent production are established, involving three types of development mode such as depletion development, barrier water injection development and barrier plus pattern water injection development. For depletion development, rational oil recovery rate increases with rational gas recovery rate; for barrier water injection development, the rational position of barrier water injection well moves towards the inner oil-gas contact with the increase of gas recovery rate and injection-production ratio; for barrier plus pattern water injection development, the rational ratio of barrier water injection to pattern water injection increases with gas recovery rate and injection-production ratio. By improving the well network of barrier plus pattern water flooding and the ratio of barrier water injection to pattern water injection, the concurrent of oil rim and gas cap of A South reservoir was carried out. Furthermore, 2.3 billion of natural gas was yielded yearly. The control degree of water flooding of oil rim was enhanced; the natural decline rate of oil rim decreased and the development effect of oil rim improved greatly.

Research the migration pattern of oil-gas interface in gas cap expansion reservoir

Gas is continuously driven into the oil rim with the decrease of the oil rim pressure during the process of gas-cap expansion. In order to study the morphological changes in the process of oil-gas interfacial migration, the one-dimensional displacement device is used to analyze the oil-gas interface at different displacement angle and displacement velocity. The results show that the migration of outer boundary is faster than the inner boundary of the oil and gas interface in the process of oil-gas interfacial migration, and there are big differences in migration pattern of oil-gas interface at different displacement angle and displacement velocity. In order to quantitative character the interface morphology with different the displacement angle and displacement velocity, the new factor is used to describe the oil and gas interface morphology and the value of the factor can be calculated using the displacement angle and displacement velocity. The relationship between oil-gas interface form factor and displacement velocity is logarithmically determined for different displacement angles, which can provide guidance for the rational exploitation of gas-cap expansion energy with gas cap reservoir to achieve the aim of improving the overall development effect of gas cap reservoir

Fluid interface moving for the concurrent production of gas cap and oil ring of gas cap reservoirs

Abstract The pressure balance between gas cap and oil ring is likely to be broken during their concurrent production in gas cap reservoirs. In order to increase the whole development efficiency of the concurrent production of gas cap and oil ring, the Zhanzhol gas cap reservoir of Kazakhstan was taken as example to carry out the research, a three-dimensional visualization physical model was established based on the similarity criterion of oil phase, gas phase and water phase, and a reservoir engineering model of fluid interface moving rate was also set up according to the material balance principle. The calculation results of reservoir engineering model tally with the results of physical simulation experiment and reservoir dynamic test data. The moving rate template of fluid interface under three development modes, depletion development, barrier water injection development and barrier plus pattern water injection development have been also established by reservoir engineering method. The main controlling factors under different development modes have been figured out: for depletion development, the main controlling factors on the stabilization of oil-gas contact are oil recovery rate and gas recovery rate; for barrier water injection development, the main controlling factors are oil recovery rate, gas recovery rate and production-injection ratio; and for barrier plus pattern water injection development, the main controlling factors are oil recovery rate, gas recovery rate, production-injection ratio and the ratio of barrier water injection to pattern water injection.

The Development and Technology Policy for a Gas Cap and Edge Water Reservoir with Narrow Oil Ring

Reservoir with gas cap, edge water is complex. And the oil-water and oil-gas interface will seriously influence the performance. Once out of control, gas and water invasion may occur, then oil productivity will fall sharply and oil recovery will become low. In addition, the oil penetrating into gas cap would lead to oil loss. So, the controlling methods are crucial. In this paper, we study the productive characteristics of a certain reservoir with gas cap, edge water and narrow oil ring. For the phenomenon several productive wells appeared gas breakthrough and water invasion after putting into production, this paper puts up a strategy shutting in high gas-oil ratio wells and blocking off gas breakthrough layers that proved effective. At the same time, adjusting oil and gas distribution underground by gas-water alternate also be proved practicable.

Study on the Reasonable Development Method of Gas Cap Reservoir

Study on the Reasonable Development Method of Gas Cap Reservoir

Development Strategy Research and Practice on Reservoir with Big Gas Cap and Narrow Oil Rim in Bohai Bay

Reservoir of Es3-I in JZ25-1S oilfield in Bohai bay is a fault type characterizing in big gas cap, narrow oil rim and edge water. The main development problem in gas cap reservoir with vertical wells is coning from gas cap, which causes the oil wells ring gas channeling and seriously affects well productivity. Faced with a number of negative factors and aimed at low development degree of vertical wells, researchers present development from horizontal wells and apply a pilot test and numerical simulation to demonstrate the adaptability. Compared with vertical wells, some obvious advantages of horizontal wells can be demonstrated by deliverability, individual-well controlled reserves, and final development efficiency. The orientation, vertical location, trajectory and length of horizontal wells and production speed in the study areas were also optimally designed. In this optimal design, the length of horizontal segment should be 400 meters; while the vertical distance between the WOC should be a third, and conversely, two-third between the GOC. The horizontal well technology is proved to be helpful for the economic and high efficiency development in Es3-I oilfield. It is showed by the mining practice of horizontal well technology in seven horizontal wells located in the gas cap of JZ25-1S oilfield Es3-I reservoir that the application is good and the daily oil production of the single well is high, from 150 to 300 m3/d. It is proved that there is great potential of the horizontal well in development of the reservoirs with big gas cap and narrow oil rim, which can significantly increase the economic benefits of offshore oil fields and provides a reference for the development of other similar reservoirs. Key words : Bohai bay; Big gas cap; Narrow oil rim; Horizontal well; Numerical simulation

Characteristics of Jurassic mudstone overpressure and its control on oil and gas accumulation in Turpan Depression

Abstract The reservoirs discovered in the Turpan Depression are mainly distributed in the Middle Jurassic, some distributed in the Upper Jurassic, Cretaceous, and Tertiary. The characteristics of the mudstone overpressure are studied to reveal the relationship between reservoir distribution and mudstone overpressure. There are several overpressure mudstone cap-rocks in the depression, of which the most steady and the best one is in the Middle Jurassic Qiketai Formation. The distribution of reservoirs in the Jurassic and the sequences above is dominantly controlled by mudstone overpressure. In the regions without mudstone overpressure, reservoirs are often destroyed because of frequent fault activities. Reservoirs have different dependence on the overpressure mudstone sealing. Overpressure mudstone seals oil reservoirs indirectly, although it seals gas reservoirs and gas-cap reservoirs directly. Without rock salt or gypsum in the multicycle basins in West China, mudstone overpressure plays an important role in hydrocarbon accumulation and reservoir preservation.

Production Strategy for Thin-Oil Columns in Saturated Reservoirs

Summary Maximizing oil recovery in thin and ultrathin (<30 ft) oil columns is a challenge because of coning or cresting of unwanted fluids, regardless of well orientation. Significant oil is left behind above the well completion even for horizontal wells when bottom- or edge-water invasion occurs. Two depletion strategies may be enacted to improve recovery of the remaining oil. In the first option, a conventional horizontal is completed below the gas/oil contact (GOC). Once the well waters out, the well is recompleted in the gas zone. Completion occurs either at the crest for a small gas-cap reservoir or at the GOC, inducing reverse cone, for reservoirs with thick-gas columns. Alternatively, one can skip the initial oil completion, where gas disposition is a nonissue. Gravity-stable flooding is required to maximize reserves. Extensive flow simulations in multiple, history-matched models have shown that the proposed strategy improves recovery significantly. Two field examples are presented to demonstrate the usefulness of the proposed method. Using multivariate regression, simple correlations were developed for quick screening of the proposed approach. Experimental design formed the backbone of a parametric study involving various reservoir, fluid, and process variables. We tested and validated the correlations with independent sets of experimental and published field data.

Simulated Production Behaviour of Heavy Oil Pools With Gas Caps

Abstract A number of thin heavy oil pools in Western Canada are being produced in which gas coning is unavoidable, even with long horizontal wells. The petroleum literature tends to have an abundance of cases where there is an associated gas cap over a thick, low viscosity oil leg that can theoretically be produced without appreciable gas coning. Gas/water coning evaluation is often restricted to the analytical calculation of breakthrough times and critical coning rates. Thus, work in the literature has limited applicability in thin oil columns of heavy oil pools. This paper reviews the unique production characteristics of those pools where gas coning is typical and discusses the underlying reservoir mechanisms associated with that production signature. In the case of a thin heavy oil pool, there may exist four distinct periods during a well's life. The first period is pre-breakthrough, the next is post-breakthrough where there is a rising gas-oil ratio, then a period identified by a decreasing gas-oil ratio and, finally, a period of relatively flat gas-oil ratio. Wellbore dynamics, standoff distance, gas cap thickness and areal extent, oil zone thickness and drainage area, vertical and horizontal permeability, oil viscosity, solution-gas oil ratio, and relative permeability all combine to control the production signature. Introduction Historically much of the literature(1-11) dealing with coning has focused on critical coning rates and breakthrough time, but very little discussion has been devoted to post-cone breakthrough response. There are many situations where production rates must exceed critical coning rates to be economic. This is particularly true in reservoirs with thin oil columns. Although horizontal wells may increase oil recovery and decrease GOR production signatures in thin oil columns, they generally cannot totally alleviate gas/water coning. TABLE 1: Summary of layer properties in reservoir model. Available in Full Paper. This paper investigates the behaviour of heavy oil pools in which small gas caps exist. One very unusual characteristic of these pools and drive mechanism is that gas-oil ratio (GOR) may decline with time or pressure depletion. This is in contrast to solution gas drive systems or in large gas cap reservoirs where, for the large majority of project life, the GOR is increasing. This work uses simulation as a tool to understand oil production and GOR profiles. Description of Simulation Model Simulations were performed for a horizontal well on 400 m spacing. The objectives of the simulations were to predict GOR behaviour in horizontal wells and to examine the sensitivity of the GOR profile to: gas cap vs. no gas cap, gas cap size, oil viscosity, pay thickness, etc. A 40 ? 21 ? 6 grid was used, representing a 800 m ? 399 m ? 4 m volume of reservoir. A uniform area grid was used. All grid blocks had areal (xy) dimensions of 20 m ? 19 m. The thicknesses (z) of the grid blocks were 0.8 m for the top layer and 0.64 m for the remaining five layers. Tables 1 and 2, as well as Figures 1 and 2, show the reservoir and model parameters.

Seismic modeling in viscoelastic media

Anelasticity is usually caused by a large number of physical mechanisms which can be modeled by different microstructural theories. A general way to take all these mechanisms into account is to use a phenomenologic model. Such a model which is consistent with the properties of anelastic media can be represented mechanically by a combination of springs and dash‐pots. A suitable system can be constructed by the parallel connection of several standard linear elements and is referred to as the general standard linear solid rheology. Two relaxation functions that describe the dilatational and shear dissipation mechanisms of the medium are needed. This model properly describes the short and long term behaviors of materials with memory and is the basis for describing viscoelastic wave propagation. This work presents two‐dimensional (2-D) and three‐dimensional (3-D) forward modeling in linear viscoelastic media. The theory implements Boltzmann’s superposition principle based on a spectrum of relaxation mechanisms in the time‐domain equation of motion by the introduction of the memory variables. The algorithm uses a polynomial interpolation of the evolution operator for time integration and the Fourier pseudospectral method for computation of the spatial derivatives. This scheme has spectral accuracy for band‐limited functions with no temporal or spatial dispersion, a very important fact in anelastic wave propagation. Examples are given of how to pose typical problems of viscoelastic forward modeling for geophysical problems in two and three dimensions. A model separating an elastic medium of a viscoelastic medium with similar elastic moduli but different attenuations shows that the interface generates appreciable reflected energy. A second example computes the response of a single interface in the presence of highly dissipative sandstone lenses, properly simulating the anelasticity of direct and converted P‐ and S‐waves. A common‐shot reflection survey over a gas cap reservoir indicates that attenuation significantly affects the bright spot response. 3-D viscoelastic modeling requires twice the memory storage of 3-D viscoacoustic modeling when one dissipation mechanism is used for each wave mode. Simulation in a 3-D homogeneous viscoelastic medium shows how the anelastic characteristics of the different modes can be controlled independently. The result of this simulation is compared to the analytical solution indicating sufficient accuracy for many applications.

Pressure Transient Analysis for Afterflow-Dominated Wells Producing From a Reservoir With a Gas Cap

Summary A method for analyzing afterflow-dominated transient pressure buildup data from a partially penetrating well completed near a gas cap is developed. The gas cap modifies the middle-time region of pressure curves in a manner such that conventional pressure buildup analysis no longer can be applied. For a damaged well, the method becomes nonunique and requires specification on the well damage to estimate the reservoir transmissibility. Introduction Buildup tests in reservoirs with a gas cap exhibit a specific performance: a continuous flattening of the pressure curve at the middle-time region (MTR) with an approach to a constant pressure value at the late time. Such behavior makes the middle-time pressure data so distorted that in a Horner plot the straight-line portion of the MTR cannot be identified. This makes it impossible to determine reservoir and wellbore parameters by the standard procedures, which are based on the MTR slope of pressure data. A method for analyzing transient pressure buildup data in a well of partial completion producing from a gas-cap reservoir is given here. The buildup data discussed are affected by afterflow. The method is based on type curves generated by applying the McKinley afterflow routine to a dimensionless pressure drawdown (buildup) function developed for a well of limited flow entry producing at a constant rate from an oil zone under a gas cap. A working set of type curves is prepared for various well penetration ratios. Information obtained from type-curve application includes wellbore and formation transmissibilities, well damage or stimulation, flow efficiency, and formation productivity. If the well is undamaged, the curve-matching technique gives an unambiguous analysis. But if the well is damaged, the analysis of the pressure buildup data is found to be nonunique: many combinations of damage and formation parameters will produce nearly the same buildup pattern. For a damaged well, an extension is made to give an indication of wellbore permeability relative to the bulk formation permeability - i.e., to determine formation transmissibility and flow efficiency for a given depth of damage. Thus, the analysis of damaged wells is reduced to the problem of assessing a range of the possible formation and wellbore properties consistent with a reasonable depth of damage. Effect of Gas Cap on Well Pressure Behavior High oil recoveries with free-gas drive are maintained as long as the gas cone does not break into the producing section of the wellbore. To reduce gas coning, producing wells in reservoirs with a gas cap often are completed such that they are open only in the lower part of the oil zone. As oil is withdrawn, the decrease in the oil volume causes the gas, compressed initially under reservoir pressure, to expand. This maintains a fairly constant pressure on the oil. The period when the pressure at the advancing gas/oil interface is relatively constant is the period of efficient oil production. A gas cap, forming a nearly constant pressure boundary at the top of the oil zone, causes vertical oil-flow components that modify the otherwise radial flow to a wellbore. The performance of a gas-cap-dominated well is affected in such a manner that a conventional transient buildup or drawdown plot shows a continual flattening of the pressure-time curve. The flattened pressure curve, which gradually approaches the horizontal, gives rise to a variety of slopes, none of them yet justified for determination of the formation properties. JPT P. 743^