A Correlation for the Increase in Gas Gravity During Pressure Depletion of a Dissolved Gas/Oil Reservoir

1987 ◽  
Author(s):  
R.D. Ostermann ◽  
S. Qadeer ◽  
K. Dehshani
Keyword(s):  
Oil Reservoir ◽  
Gas Oil ◽  
Dissolved Gas ◽  
Pressure Depletion

scholarly journals Experimental Investigation of Oil Recovery from Tight Sandstone Oil Reservoirs by Pressure Depletion

Energies ◽  
2018 ◽  
Vol 11 (10) ◽  
pp. 2667 ◽  
Author(s):  
Wenxiang Chen ◽  
Zubo Zhang ◽  
Qingjie Liu ◽  
Xu Chen ◽  
Prince Opoku Appau ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Reservoirs ◽  
Oil Reservoir ◽  
Reservoir Pressure ◽  
Dissolved Gas ◽  
Tight Sandstone ◽  
Bubble Point ◽  
Bubble Point Pressure ◽  
Pressure Depletion ◽  
Point Pressure

Oil production by natural energy of the reservoir is usually the first choice for oil reservoir development. Conversely, to effectively develop tight oil reservoir is challenging due to its ultra-low formation permeability. A novel platform for experimental investigation of oil recovery from tight sandstone oil reservoirs by pressure depletion has been proposed in this paper. A series of experiments were conducted to evaluate the effects of pressure depletion degree, pressure depletion rate, reservoir temperature, overburden pressure, formation pressure coefficient and crude oil properties on oil recovery by reservoir pressure depletion. In addition, the characteristics of pressure propagation during the reservoir depletion process were monitored and studied. The experimental results showed that oil recovery factor positively correlated with pressure depletion degree when reservoir pressure was above the bubble point pressure. Moreover, equal pressure depletion degree led to the same oil recovery factor regardless of different pressure depletion rate. However, it was noticed that faster pressure drop resulted in a higher oil recovery rate. For oil reservoir without dissolved gas (dead oil), oil recovery was 2–3% due to the limited reservoir natural energy. In contrast, depletion from live oil reservoir resulted in an increased recovery rate ranging from 11% to 18% due to the presence of dissolved gas. This is attributed to the fact that when reservoir pressure drops below the bubble point pressure, the dissolved gas expands and pushes the oil out of the rock pore spaces which significantly improves the oil recovery. From the pressure propagation curve, the reason for improved oil recovery is that when the reservoir pressure is lower than the bubble point pressure, the dissolved gas constantly separates and provides additional pressure gradient to displace oil. The present study will help engineers to have a better understanding of the drive mechanisms and influencing factors that affect development of tight oil reservoirs, especially for predicting oil recovery by reservoir pressure depletion.

The Development of an Oil Reservoir with Condensate Gas Cap

2012 ◽  
Vol 524-527 ◽  
pp. 1615-1619
Author(s):  
Heng Song ◽  
Lun Zhao ◽  
Jian Xin Li ◽  
Kou Shi
Keyword(s):  
Numerical Simulation ◽  
Oil And Gas ◽  
Oil Reservoir ◽  
Gas Oil ◽  
Gas Reservoir ◽  
Oil Rim ◽  
High Level

The development of gas-oil reservoir with condensate gas is more difficult than pure gas reservoir or oil reservoir. This article gives the example of G oil reservoir the development of gas cap and oil rim. According to the characteristic of the oil developing and the results of numerical simulation, the rules for oil and gas developing and developing time have been defined, by which the recoveries of gas, oil, and condensate oil will reach a significantly high level.

Convection in Fractured Reservoirs Numerical Calculation of Convection in a Vertical Fissure, Including the Effect of Matrix-Fissure Transfer

1976 ◽  
Vol 16 (05) ◽  
pp. 281-301 ◽  
Author(s):  
D.W. Peaceman
Keyword(s):  
Fractured Reservoirs ◽  
Saturation Pressure ◽  
Fractured Reservoir ◽  
Density Inversion ◽  
Dissolved Gas ◽  
Rectangular Shape ◽  
Pressure Depletion ◽  
Matrix Blocks ◽  
The Matrix ◽  
Transfer Parameters

Abstract A fractured reservoir undergoing pressure depletion, evolution of gas at the top of the oil zone leads to an unstable density inversion in the fissures. The resulting convection brings heavy oil into contact with matrix blocks containing light oil, and results in the transfer of dissolved gas between matrix and fissure in the undersaturated region of the oil zone. To provide a better understanding of this process, numerical solutions were obtained to the differential equations that describe convection in a vertical fissure and include the matrix-fissure transfer. The numerical procedure is an extension of the method of characteristics for miscible displacement problems in two dimensions. The effect of gas evolution in the upper portion of the oil zone is also included in the numerical model. Calculations for a vertical fissure of rectangular shape, with an initial sinusoidal perturbation of an in verse density gradient, show an initial exponential growth of the perturbation that agrees well with that predicted from mathematical theory. Calculations predicted from mathematical theory. Calculations for a vertical fissure having a similar, but slightly tilted, rectangular shape and with an initial, correspondingly tilted, inverse density gradient, show that the effect of the matrix-fissure transfer parameters on the time for overturning can be parameters on the time for overturning can be correlated quite well by curves obtained from mathematical perturbation theory. The most realistic calculations were carried out for the same vertical fissure having a slightly tilted rectangular shape, with declining pressure at the apex and gas evolution included in the gassing zone. The relative saturation-pressure depression in the fissure below the gassing zone can be characterized as increasing as the square of the time, following an incubation period. For practical ranges of the matrix-fissure period. For practical ranges of the matrix-fissure transfer parameters investigated, it is concluded that saturation-pressure depression will be significant. A preliminary correlation for this Pb depression was obtained. The fissure thickness was found to affect the Pb depression significantly. Introduction Most fractured reservoirs of commercial interest are characterized by the existence of a system of high-conductivity fissures together with a large number of matrix blocks containing most of the oil. It has been recognized for some time that analysis of the behavior of a fractured reservoir must involve an understanding of the performance of single matrix blocks under the various environmental conditions that can exist in the fissures. However, it has only recently been recognized that a similar need exists for a better understanding of convective mixing taking place within the oil-filled portion of the fissure system. In a fractured reservoir undergoing pressure depletion, gas will be evolved at all points of the reservoir where the oil pressure has declined below the original saturation pressure. This depth interval is referred to as the gassing zone. Because of the high conductivity of the fracture, the gas in the fissures will segregate rapidly from the oil before reaching the producing wells and most, if not all, of it will join the expanding gas cap. At a sufficient depth, however, the oil pressure will still be higher than the saturation pressure, and the oil there remains in an undersaturated condition. In the gassing zone, gas evolves from the oil in both the fissures and the matrix. The oil left behind in the fissures within the gassing zone contains less dissolved gas and is heavier than the oil below it in the undersaturated zone. This density inversion can result in considerable convection within the highly conductive fissures. As a result of this convection, heavy oil containing less gas is transported downward through the fissures, placing it in contact with matrix blocks containing lighter oil with more dissolved gas. Transfer of dissolved gas from matrix to fissure takes place owing to molecular diffusion through the porous matrix rock; and even more transfer takes place owing to local convection within the matrix block induced by the density contrast between fissure and matrix oil. SPEJ p. 281

Convection in Fractured Reservoirs - The Effect of Matrix-Fissure Transfer on the Instability of a Density Inversion in a Vertical Fissure

1976 ◽  
Vol 16 (05) ◽  
pp. 269-280 ◽  
Author(s):  
D.W. Peaceman
Keyword(s):  
Fractured Reservoirs ◽  
Saturation Pressure ◽  
High Conductivity ◽  
Fractured Reservoir ◽  
Density Inversion ◽  
Dissolved Gas ◽  
Rate Of Growth ◽  
Pressure Depletion ◽  
Matrix Blocks ◽  
The Matrix

Abstract In a fractured reservoir undergoing pressure depletion, evolution of gas at the top of the oil zone leads to an unstable density inversion in the fissures. The resulting convection brings heavy oil into contact with matrix blocks containing light oil, and results in the transfer of dissolved gas between matrix and fissure in the undersaturated region of the oil zone. To provide a better understanding of dis process, an earlier perturbation analysis of a density inversion in a vertical fissure has been extended to include the matrix-assure transfer. It was found that matrix-fissure transfer does not affect the stability or instability of a density inversion, nor does it affect the spacing of density angers or the size of convection cells. A quantitative expression for the rate of growth of unstable density fingers was derived. The effect of matrix-fissure transfer is always to reduce the rate of growth. For practical reservoir cases, while any density inversion should be highly unstable, matrix-fissure transfer can be expected to cause a significant reduction in the linger growth rate. Introduction Most fractured reservoirs of commercial interest are characterized by the existence of a system of high-conductivity fissures together with a large number of matrix blocks containing most of the oil. It has been recognized for some time that the analysis of the behavior of a fractured reservoir must involve an understanding of the performance of single matrix blocks under the various environmental conditions that can exist in the fissures. However, only recently has it been recognized that a similar need exists for a better understanding of the convective mixing that probably takes place within the oil-filled portion of the fissure system. In a fractured reservoir undergoing pressure depletion, gas will be evolved at all points of the reservoir where the oil pressure has declined below the original saturation pressure. This depth interval is referred to as the gassing zone. Because of the high conductivity of the fracture, the gas in the fissures will segregate rapidly from the oil before reaching the producing wells and most, if not all, of it will join the expanding gas cap. At a sufficient depth, however, the oil pressure will still be higher than the saturation pressure, and the oil there remains in an undersaturated condition. (See Fig. 1.) In the gassing zone, gas evolves from the oil in both the fissures and the matrix. The oil left behind in the fissures within the gassing zone contains less dissolved gas and is heavier than the oil below it in the undersaturated zone. SPEJ P. 269

Research of Advanced GTM and Its Application to Gas-Oil Reservoir Identification

2017 ◽  
Vol 31 (05) ◽  
pp. 1750015 ◽  
Author(s):  
Meihong Wang ◽  
Qingqiang Wu
Keyword(s):  
Euclidean Distance ◽  
Seismic Exploration ◽  
Oil Reservoir ◽  
Oil Exploration ◽  
Gas Oil ◽  
Generative Topographic Mapping ◽  
Seismic Attribute ◽  
Data Set ◽  
Actual Application ◽  
Reservoir Identification

Identification of gas-oil reservoir is always important but rather difficult in global gas-oil exploration. It is of the great significance to improve the accuracy of reservoir recognition. Seismic exploration is one of the most valuable methods of gas-oil exploration, and the huge amounts of seismic attribute data can be useful for gas-oil exploration. One limitation of the Generative Topographic Mapping (GTM) algorithm is that it cannot determine the classifications of the data points with close probabilities accurately, and it would be more likely to result in confused clarification and fuzzy boundary. To overcome the limitation, an advanced GTM algorithm with Euclidean Distance (GTM-ED) is proposed in this paper, and we use Euclidean Distance to compute the distance from the edge points to the neighbor centroids, and classify it to the closet class to avoid the problems of confused classification. And then the GTM-ED algorithm is used in the research of reservoir identification model, experiments are made with actual seismic data set. First of all, the GTM algorithm is discussed, and then the GTM-ED algorithm is introduced. And afterwards, many experiments are made. In the experiments, the log data and geological data are selected as the labels, and the comparison and analysis are made through three aspects, including relative criteria, absolute criteria, and run-time, and then the results of each model are visualized. The experimental results indicate that the GTM-ED can achieve better results in reservoir clustering and unknown reservoir identification. And in the actual application, the visualization of the GTM-ED can behave better than the GTM in showing the geological characteristics of paleochannel, the string of beads-like reservoirs and linear lava.

Integrated Subsurface Study for Gas-Oil Communicating Reservoirs: From Structural Synthesis to Optimum Co-FDP

2021 ◽  
Author(s):  
Mohamad Yousef Alklih ◽  
Andi Ahmad Salahuddin ◽  
Karem Alejandra Khan ◽  
Nidhal Mohamed Aljneibi ◽  
Coriolan Rat ◽  
...  
Keyword(s):  
Decision Making ◽  
Reservoir Characterization ◽  
Development Planning ◽  
Co2 Injection ◽  
Oil Reservoir ◽  
Discounted Cash Flow ◽  
Field Development ◽  
Development Scenarios ◽  
Pressure Depletion ◽  
Field Management

Abstract This paper presents an integrated subsurface study that focuses on delivering field development planning of two reservoirs via comprehensive reservoir characterization workflows. The upper gas reservoir and lower oil reservoir are in communication across a major fault in the crest area of the structure. Gas from the upper reservoir, which is not under development, is being produced along with some oil producers from the oil reservoir as per acquired surveillance data. Pressure depletion is observed in observer wells of the upper reservoir, which substantiate both reservoirs communication. The oil reservoir is on production since 1994, under miscible hydrocarbon water alternating gas injection (HCWAG) and carbon dioxide (CO2) injection. The currently implemented development plan has been facing several complexities and challenges including, but not limited to, maintaining miscibility conditions, sustainability of production and injection in view of reservoirs communication, reservoir modeling challenges, suitability of monitoring strategy, associated operating costs and expansion of field development in newly appraised areas. In this study, an assessment of multiple alternative field development scenarios was conducted; with an aim to tackle field management and reservoir challenges. It commenced by a comprehensive synthesis of seismic, petrophysical (including extensive core characterizations), geological, production and reservoir engineering data to ensure data adequacy and effectiveness for development planning. The process was followed by evaluation of the historical reservoir management, HCWAG and CO2 injection practices using advanced analytics to identify areas for improvement and accelerate decision making process. The identified areas of improvement were incorporated into a dynamic model via diverse set of field management logics to screen wide range of scenarios. In the final step, the optimal scenarios were selected, in line of having strong economic indicators, honoring operational constraints, corporate business plan and strategic objectives. The comprehensive and flexible field management logic was set up to target different challenges and was used to extensively screen hundreds of different field development scenarios varying several parameters. Examples of such parameters are WAG ratio, injection pressures for both water/gas and CO2, cycle duration, well placement, reservoir production and injection guidelines, different co-development production schemes coupled with static and dynamic uncertainty properties against incremental oil production and discounted cash flow. The simulation results were analyzed using standardized approach where a number of key indicators was cross-referenced to produce optimal field development scenarios with regards to co-development effect of both reservoirs, miscibility conditions, balanced pressure depletion, harmonized sweep as well as robust discounted cash flow. Strong management support, multi-disciplinary data integration, agility of decision making and revisions in a controlled timeframe are considered as the key pillars for success of this study. The adopted workflow covers subsurface modeling aspects from A-Z and following reservoir characterization and modeling best practices. The methodology applied in this study uses an integrated subsurface structured approach to tackle reservoirs challenges and co-development, generate alternative development options leveraging on data analytics techniques and advanced field management strategies.

Simultaneous Production of Gas Cap and Oil Column With Water Injection at the Gas/Oil Contact

1999 ◽  
Vol 2 (05) ◽  
pp. 412-419 ◽  
Author(s):  
T.C. Billiter ◽  
A.K. Dandona
Keyword(s):  
Oil Recovery ◽  
Pressure Support ◽  
Gas Production ◽  
Oil Field ◽  
Oil Reservoir ◽  
Horizontal Distance ◽  
Gas Oil ◽  
Simultaneous Production ◽  
Original Oil In Place ◽  
Dip Angle

Summary The conventional way to produce an oil reservoir that has a gas cap is to produce only from the oil column while keeping the gas cap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gas cap and oil column. This methodology has application in reservoirs with a low-dip angle, large gas cap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. Geostatistical reservoir models are used to demonstrate that the gas cap recovery is minimally impacted by heterogeneities. Introduction of the Concept The conventional way to produce an oil reservoir that has a gas cap is to produce the oil column while minimizing production from the gas cap. During the pressure depletion of the reservoir, the gas cap will expand to provide pressure or energy support. After the oil column is depleted, the gas cap is "blown down." In developing a production strategy for an oil reservoir with a large gas cap, a low-dip angle, and an available gas market, simultaneous waterflooding of the gas cap and oil column was evaluated. The water is injected at the gas-oil contact at rates high enough to overcome gravity effects and thus, the water displaces the gas up dip. In addition to providing pressure support, the created water wall separates the gas cap and the oil column regions. Since the development plan calls for the use of electrical submersible pumps (ESPs) in the oil producing wells, it is imperative to keep the gas production volumes from these oil wells at low levels so the ESPs will operate smoothly. As such, it is critical to control the downward migration of the gas cap. To maintain the reservoir pressure, water is injected not only at the gas-oil contact but also around the downdip periphery of the oil column to support the oil withdrawal rates. A simplistic representation of the simulated structure is shown in Fig. 1. This figure shows the location of the gas-oil contact, along with the location of the water injector at the gas-oil contact and of the gas cap producer. The reservoir considered in this study has a dip angle of 2°. For the purposes of illustration the dip angle has been exaggerated in Fig. 1. The horizontal distance between the injector and producer is 12,155 feet. The structural elevation difference between these two wells is 425 feet. Taking into account the density difference between the water and gas, the injected water must overcome a gravity component of 149 psi in addition to the energy required for the water to displace the gas. The possibility of injecting water at high enough rates to overcome both the gravity and displacement components is shown in this paper. The main objective of this paper is to present the concept of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact. The application of this concept for a newly discovered, offshore oil field has been studied. In this study, the majority of the effort was dedicated to theoretically proving this concept, as opposed to optimizing the number of wells and placement of wells to increase the recovery factors for oil and gas. This production methodology should be applicable to other reservoirs with similar characteristics. Partial Proof of Concept A literature survey indicated that the simultaneous production of the gas cap and oil column while injecting water at the gas-oil contact, has never been documented. However, four case histories were found in which water was injected at the gas-oil contact for the sole purpose of preventing the migration of the gas cap down structure. By preventing this migration, increased oil recoveries were realized. In these four cases, the gas cap was not produced during the depletion of the oil column. One successful application of this production methodology was to the Adena field in the Denver basin in 1965.1 By injecting water at the gas-oil contact, the operator was able to keep the producing gas-oil ratio value close to the solution gas-oil ratio value for an extended time. The ultimate oil recovery was estimated to be 47% of the original oil in place. The methodology of injecting water at the gas-oil contact was also applied in seven of the oil reservoirs of the Algyo Field in Hungary.2 These seven reservoirs are thin oil edge zones with large gas caps. The operators of this field were able to increase oil recovery by over 10% of original oil in place by using this methodology. In the Canadian oil field Kaybob South, the injection of water at the gas-oil contact was studied by Deboni and Field.3 They used numerical simulation to determine that a waterflood can be successfully implemented adjacent to a gas cap if a proper water "fence" is established between the gas cap and oil column. The authors concluded that an additional 10% of the oil in place can be recovered.

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