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Abstract CO2 geological storage is about pumping a reactive fluid underground and ensuring it doesn't find a way back to the atmosphere for a very long time - possibly centuries. Potable aquifers and other permeable formations (e.g. hydrocarbon deposits) must also be protected against CO2 contamination. Wells are generally recognized as a weak spot in CO2 storage, where containment can break down. This is because cement, steel and elastomers can be corroded by CO2, and the ageing process will be accelerated by any defects in the cement sheath. It is therefore of critical importance to understand and characterize fluids and solids across the caprock. This has the triple aim of: verifying the soundness of the complex cementing engineering process, evaluating the capacity of cement to provide short-term zonal isolation, and providing measures that can be used to predict the evolution of cement and casing over the long term. This paper will focus on an in-depth evaluation of the annular material on the Otway CRC-1 well that is being used to inject CO2 in the CO2CRC pilot geological storage project. The evaluation will draw on the design and job data, and on a detailed analysis of the high-resolution 3D cement imaging log to characterize the cement and ensure the long-term risk of containment breach is minimized. The essentially unpredictable nature of fault-free risk - i.e. the unplanned events in a job otherwise designed and executed to the highest standards - always requires a number of mitigation measures to minimize the residual risk of CO2 leaks. This paper will show that the adoption of a number of them on Otway (e.g. excess volumes and CO2-resistant cement system) have been essential in achieving the containment objectives. Introduction Cement slurries are exposed to a number of phenomena during mixing and placement that can lead to set cement properties that are very different from their design value. Density control problems (both for continuous and batch mixing), contamination, channeling and fluid loss can and do cause slurry dilution/concentration and chemical incompatibility, which in turn can have a major negative effect on the capacity of cement to guarantee hydraulic isolation and can even lead to premature gelling during placement and early job termination. It is currently hotly debated whether ten or more meters of competent cement, well bonded to casing and formation would degrade during the expected isolation timeframe for CO2 geological sequestration wells (1,000's to 10,000 years). This is because competent cement, although reactive if exposed to CO2, has a very low permeability of the order of 0.5 to 5 µD; this low permeability means that most CO2 will travel by diffusion, a very slow process over the length scale of a meter. Cement with a high w/c ratio, however, could have a much higher permeability, less resistance to CO2 aggression and more frequent defects related to slurry settling. Defects such as liquid channels in cement can even provide direct pathways for CO2 leaks that couldn't possibly be healed by calcite precipitation during the CO2 attack. Some of the phenomena listed above can be predicted, but cannot easily be controlled; others (such as fluid loss) can hardly be predicted at all. In any case they belong to the class of fault-free risk, sometimes called residual risk: events causing sub-standard system performance that cannot be engineered away and that may happen even when job is perfectly executed. Mitigation measures must be adopted in this case to ensure a robust design. This is especially true for wells entering CO2 storage reservoirs, where storage containment is a key performance factor and CO2-cement reactions may cause leaks to grow over time.
- North America > United States (0.46)
- Asia (0.28)
Abstract Emulsified acid (30 vol% diesel and 70 vol% HCl acid) has been used in both matrix and acid fracturing treatments. Injection the acid in this form has several advantages including: retard the reaction of the acid with rock, reduce corrosion to well tubulars and minimize acid additives. However, using this acid to treat wells with asphaltene deposition will require removing asphaltene first using a suitable aromatic-based solvent, and then using a matrix acid treatment. This additional step will increase the cost and time needed to execute acid treatments. To remove asphaltene deposition and enhance well productivity, hydrochloric acid was emulsified in xylene. Xylene was the external phase, and was used to dissolve asphaltenes. Then the acid, present as the dispersed phase dissolved the carbonate rock, thus enhancing well productivity. Extensive lab work was performed to ensure the stability of acid-in-xylene emulsion and measure its apparent viscosity. Acid concentration was 15 wt% HCl, the acid volume fraction was 0.7 and the balance was xylene. All tests were conducted at room temperature and 160oF. The stability and apparent viscosity of emulsified acids were found to be a function of the type of hydrocarbon phase used to prepare emulsified acid. Emulsified acids prepared with xylene had a lower apparent viscosity and were stable for relatively shorter period of times. A matrix acid treatment was that based on xylene emulsified acid was applied in four wells without encountering operational problems. Unlike previous matrix acid treatments using regular acid, the four wells responded to the new treatment, without increasing water-cut, except in one well which was wet before the treatment. Introduction Diesel is commonly used to prepare emulsified acids. It acts as a diffusion barrier between the acid and the rock (Crowe and Miller, 1974; Bergstrom and Miller, 1975, Hoefner and Fogler, 1985; Daccord et al., 1987; Peters and Saxon, 1989). Thus, the reaction rate of the acid with carbonate rocks becomes slower. This gives the acid the ability to penetrate deeper into the formation by creating wormholes (i.e., channels with high permeability), which enhance well performance (Williams and Nierode, 1972; Guidry et al., 1989; Navarrete et al. 1998a,b) Acid-in-diesel emulsion has several advantages besides its slow reaction rate with the rock. It has a relatively high viscosity, which results in a better sweep efficiency that will improve acid distribution in heterogeneous reservoirs (Buijse and van Domelen, 1998). The live acid does not come in contact with well tubulars. Therefore, there is minimum corrosion to well tubulars. As a result, the concentration of iron in the live acid reaching the formation will be low, which will reduce the amount of iron control agents (Al-Anazi et al., 1998). Several studies (de Rozieres et al., 1994; Conway et al., 1999; Kasza et al., 2006; Al-Mutairi et al., 2008a) examined the reaction of emulsified acid with carbonate rocks. The rotating disk apparatus was extensively used and the results of these studies indicated that the reaction of emulsified acid with carbonate rocks is slower than that of regular acids. Al-Mutairi et al. (2008a) indicated that the size of the acid droplets affected the reaction rate. And this should be considered as an important parameter in designing acid treatments. In a second study, Al-Mutairi et al. (2008b) examined the impact of the droplet size on the rheological properties of acid-in-diesel emulsions. Propagation of emulsified acids in carbonate cores was examined by several research groups (Bazin and Abdulahad, 1999; Lynn and Nasr-El-Din, 2001; and Siddiqui et al., 2006). These studies indicated that the acid propagated through the core plugs in almost straight lines. The acid enhanced core permeability by a factor that depended on the acid injection rate.
- North America > United States > Texas (0.69)
- Asia (0.69)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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...)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (3 more...)
Abstract Gas cyclic pressure pulsing is an effective IOR method specifically for naturally fractured reservoirs. Due to the computational cost of simulating a large number of scenarios, it is an arduous task to determine the optimum operational conditions for the process. In this study, a practical screening and optimization workflow is utilized to determine the most optimum operating conditions for cyclic pressure pulsing applications with N2 and CO2 in a fully-depleted reservoir. Two huff 'n' puff design schemes with variable and constant injection volumes are implemented in a compositional, dual-porosity reservoir simulation model. A set of representative design scenarios is created and run using this model. Then, the collected performance indicators are fed into the neural network for training and two neural network-based proxies are developed:A forward proxy to predict the corresponding performance indicators once given the design scenarios, An inverse proxy to predict the corresponding design scenarios once given a set of desired performance characteristics. Finally, the genetic algorithm is used to search for the best design scenario that would maximize the efficiency of the process for a given time of operation. To evaluate the objective function, the forward proxy is used for computational efficiency. The methodology is tested with a single-well reservoir model of the Big Andy Field which is a depleted, naturally fractured reservoir in Eastern Kentucky with stripper-well production. Predictive capability and accuracy of developed networks are checked by comparing simulation outputs with network outputs. It is observed that networks are able to accurately predict the performance indicators including the peak rate, time to reach the peak rate, cycle flow rates, incremental oil production, and gas-oil-ratio. The proposed methodology is practical and computationally efficient in structuring more effective decisions towards the optimum design of the process. Introduction Cyclic pressure pulsing using different types of gases is an IOR method that is effectively applicable specifically to fractured reservoirs. In low-permeability reservoirs that are dissected by a network of interconnected fractures, solution channels, and vugs, waterflooding and gas flooding are not fully effective, since the injected fluid tends to channel through the high conductivity network and bypass the low-permeability, oil-bearing matrix.1,2 In this type of reservoirs, cyclic pressure pulsing with gas has been found to be effective. Fractures provide a large contact area for the injected gas to penetrate and diffuse through the low-permeability matrix. Also, high permeability of fracture system results in an easy delivery of both the injected gas and produced oil. Because it is a single-well process, well-to-well connectivity is not required. The payback period is rather short as compared to that of field-scale flooding projects. This makes the single-well cyclic pressure pulsing process a low-risk process with a relatively lower initial investment requirement. The process is characterized by three distinct stages: During the injection period, the gas is injected into the reservoir. After the injection period, the well is shut-in to wait for the injected gas to interact with reservoir fluids by diffusing from fractures into the matrix. This period is called the soaking period and its duration is typically 2–4 weeks. After soaking is completed, the well is put on production. Typically, a large amount of gas is produced at the beginning, while the oil production rate starts to rise and reaches a peak rate. After this point, production may continue until the economic limits are reached, and if necessary, another cycle can be initiated. In Figure 1 these stages are illustrated with their impact on the oil flow rate with time.
- North America > United States > Texas (1.00)
- Asia > Middle East (0.93)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (33 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract Decline curve analysis (DCA) is a traditional method for production prediction, which is still being used today because of its simplicity. However, DCA methods have limitations in many cases when applied to entire reservoirs. Such cases include variation in production conditions and change in the number of injection and production wells. In this study, we focused on the latter problem, change in the number of production wells. Obviously, there would be a significant oil production boost during a specific time period if more oil wells are drilled. The traditional DCA approach cannot match the increase in oil production due to the increase in the number of oil production wells. We have developed a method to match and predict the oil production of entire reservoirs by considering the change in the number of production wells. The main idea of this new approach came from the concept of effective wells. We applied this new approach in several sandstone oil reservoirs with different permeabilities. Satisfactory results were obtained. Comparison with the existing models (exponential, hyperbolic model, and harmonic models) was made and the results showed the new approach had the best fit to the production history in the cases studied. Introduction Production data are the most common data in reservoir development. Utilizing production history data to predict future performance is therefore an important aspect of reservoir engineering. There have been many methods of decline curve analysis (DCA) in estimating production and reserves (Arps, 1945; Fetkovich, 1980; Agbi and Ng, 1987; Camacho and Raghavan, 1989; Palacio and Blasingame, 1993; Masoner, 1998; Agarwal, et al., 1999; Marhaendrajana and Blasingame, 2001; Li and Horne, 2005). The frequently-used DCA model was developed by Arps (1945), including exponential, hyperbolic, and harmonic models. DCA methods are still widely used today for simplicity. However, DCA methods and other decline models have limitations in many cases when applied to the entire reservoirs. Such cases include variation in production conditions and change in the number of injection and production wells. The traditional DCA approaches cannot match the increase in oil production due to the increase in the number of oil production wells. Generally speaking, DCA methods are only suitable in the later period of production when oil production begins to decline. In this study, we developed a new approach to matching and predicting the oil production of the entire reservoirs by considering the change in the number of production wells. This approach could be suitable for most of the production stages. The main analysis process is described briefly in the following. Firstly, typical and representative oil wells were identified. Secondly, decline curve analysis to these wells was conducted to determine the models fitting the production history. Finally, these models were used as the training models; the total oil production was the sum of the production from the effective wells derived from the trained models. The change in the number of production wells was considered by setting the value of a parameter in the model to a specific value since the start of the production. We applied the new production analysis method to different reservoirs to match and predict the oil production rates. Traditional exponential, hyperbolic, and harmonic models were also used to conduct the analysis and the results were compared with the new method. Both the data of the whole production history and the data only from the period of decline were used. Different parameters such as the sum of squared residuals (SSR) and R-square were used to evaluate these different models. The reason for using the sum of squared residuals was because the regression coefficient R2 does not work in the nonlinear regression in some cases.
- Asia (0.69)
- North America > United States > Colorado (0.28)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.61)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (0.96)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.91)
Abstract Multiphase and non-Darcy flow effects in hydraulically fractured gas wells reduce effective fracture conductivity. Typical proppant pack laboratory experiments are oriented in such a way that phase segregation is not possible, which results in mixed flow. In this work, reservoir simulation modeling was used to determine the impact of gravity segregation. Gravity segregation is commonly ignored in design and analysis of hydraulically fractured gas wells. We found that by ignoring segregation, effective fracture conductivity can be underestimated by up to a factor of two. Hydraulic fracture treatments can be designed more effectively if effective fracture conductivity is known more accurately. Introduction Hydraulic fracturing in gas reservoirs is a common practice to increase production rates. Multiphase and non- Darcy flow effects in hydraulically fractured gas wells increase pressure drop down the fracture and consequently reduce effective fracture conductivity of the proppant. Using a higher permeability proppant in the design can compensate for the effective permeability reduction caused by multiphase non-Darcy flow. Taking into account multiphase non-Darcy effects in the fracture leads to more accurate modeling of the flow in the fracture and allows for the fracture treatment to be optimized. Previous work by Olson (2004) found that laboratory data for multiphase non-Darcy flow can be fit to a Geertsma (1974) type equation with good accuracy provided that the water saturation is not too high. Olson also found that at high water saturations, running experiments is more difficult, which means that there is a lack of laboratory data to compare to Geertsma's correlation at higher water saturations. Lolon et al. (2003) defined effective fracture length as the length under single-phase conditions that results in the productivity observed under multiphase conditions. They found that with increasing fracture conductivity more fracture fluid is cleaned up, which results in longer effective fracture lengths. We will use a similar concept, as we define effective conductivity to be the conductivity in single-phase flow conditions that results in the same productivity that is observed under multiphase conditions. Typical proppant pack laboratory experiments are oriented in such a way that phase segregation is not possible, which results in mixed flow throughout the fracture (i.e., both phases flowing at all locations in the fracture). If gravity segregation occurs in hydraulic fractures in the field, taking segregation into account in laboratory conductivity tests may result in more representative effective conductivity measurements. Reservoir simulation models of hydraulically fractured gas wells are commonly run with one layer. This forces mixed flow as it is not possible for phase segregation to occur within a single layer in a reservoir simulation model. Using several layers in a model is the easiest and most accurate way of taking into account gravity segregation.
- North America > United States > Texas (0.28)
- North America > United States > Louisiana (0.28)
- Asia > China > Heilongjiang Province (0.24)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Well test analysis in naturally fractured reservoirs is generally based on the radial flow model, even when it is widely believed that such reservoirs are anisotropic. The radial flow model is however only applicable to purely homogeneous system and long time solution. It cannot provide a complete formation analysis in a reservoir that exhibits anisotropy. This study therefore presents a new method of estimating permeability anisotropy in naturally fractured reservoirs. Maximum and minimum permeability are obtained in one well test. The maximum permeability is attributed to the large scale fractures in the system while the minimum permeability may be due to the small scale fractures orthogonal to the large scale fractures. In a situation where the fractures are orienting in one direction, the minimum permeability will reflect the matrix permeability. The type of flow path developed (narrow or wide flow path) can also be predicted. This is useful in predicting the direction of fluid flow. Application was made to four field examples, one of which was an interference test. The interference test was used as a validation process. The results obtained are in agreement with that of a conventional interference test method of analysis. Introduction Naturally fractured reservoirs are anisotropic systems whose flow characteristics depend on the fractures network. Their permeability variation is not only stratigraphic in nature, but is also caused by the fractures' distribution, orientation and permeability impairment within the fractures caused by pressure solution or mineralization. The reservoir becomes more complex when both the matrix and fracture exhibit anisotropy and have the capability to flow into the wellbore as in the double permeability case. According to Nelson (2001), naturally fractured reservoirs can be divided into four categories. Type 1 Fractures provide the essential porosity and permeability. Type 2 Fractures provide the essential permeability while the matrix provides the essential porosity. Type 3 Fractures assist permeability in an already producible reservoir. The matrix already has good permeability. Type 4 Fractures provide no additional porosity or permeability, but create significant reservoir anisotropy (barriers) due to mineral filled. Previous studies have shown that the fractures distribution and their permeability depend on the stress anisotropy. According to Price (Nelson, 2001), the two perpendicular orientations of most regional fracture sets are rotated to basin shape. As most basins are elliptical, one orientation of the orthogonal pattern parallels the long axis of the basin and the other parallel the short axis of the basin. High permeability fracture network will align with the maximum stress direction. Figure 1 is an example of such naturally fractured reservoir in offshore Abu Dhabi (Gouth et al, 2007). According to Gouth, the interpretation of 3D seismic shows numerous low displacement NW-SE striking normal faults cutting the reservoir (Figure 1). These faults are oriented perpendicular to the dominant trend of the open fracture system and predate the formation of the open fractures. A second set of fractures is sub-parallel to the fault trends, but since they are described as mineralized, these fractures are assumed to be healed and have little effect on fluid flow. Thus the SW-NE trending open fractures formed the maximum permeability.
- North America > United States > Texas > Midland County (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.24)
- Geology > Geological Subdiscipline > Stratigraphy (0.48)
- Geology > Geological Subdiscipline > Geomechanics (0.34)
- 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)
- (26 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract For many oil & gas reservoirs, especially large reservoirs in the Middle East, the availability of vast amounts of seismic, geologic and dynamic reservoir data result in high resolution geological models. Because of the limitations of conventional reservoir simulator technologies, high resolution models are upscaled to flow simulation models by reducing the total number of cells from millions to a few hundred thousand. Flow simulators using upscaled reservoir properties produce average reservoir performance and often fall short of accurately predicting recovery. Realizing the limitations of the conventional simulators for the giant oil and gas reservoirs, parallel reservoir simulators have been developed. The first generation of parallel simulators increased the simulator capabilities by an order of magnitude — the result was that mega (million) cell simulation became a reality. Parallel computers, including PC Clusters, were successfully used to simulate large reservoirs with long production histories, using millions of cells. Mega-cell simulation helped recover additional oil and gas due to better understanding of reservoir heterogeneity. The speed of parallel hardware also helped, making many runs to address uncertainty possible. Despite the many benefits of parallel simulation technology for large reservoirs, the average cell size still remains in the order of hundreds of meters (m) for large reservoirs. To fully utilize the seismic data, smaller grid blocks of fifty m in length are required. This size of grid block results in billion (Giga) cell models for giant reservoirs. This is a two orders of magnitude increase from the mega-cell simulation. To simulate Giga-cell models in practical time, new innovations in the main components of the simulator, such as linear equation solvers, are essential. Also, the next generation pre- and post-processing tools are needed to build and analyze Giga-cell models in practical times. This paper describes the evolution of reservoir simulator technology, from Mega-Cell scale to a Giga-Cell scale, presenting current achievements, challenges and the road map for Giga-Cell Simulators. INTRODUCTION To simulate the giant oil and gas reservoirs with sufficient resolution, parallel reservoir simulator technology is an absolute necessity since the conventional simulators based on serial computations cannot handle these systems. Interest in parallel reservoir simulation started over two decades ago in the oil industry. The earliest attempt was by John Wheeler. This was followed by work of John Killough, Shiralkar and Stevenson.
- North America > United States > Texas (0.94)
- Asia > Middle East > Saudi Arabia (0.69)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Determination of In-Situ Two-Phase Flow Properties Through Downhole Fluid Movement Monitoring
Kuchuk, Fikri J. (Schlumberger) | Zhan, Lang (Schlumberger) | Ma, Mark (Saudi Aramco) | Al-Shahri, Ali S. (Saudi Aramco) | Ramakrishnan, T.S. (Schlumberger) | Altundas, Bilgin | Zeybek, Murat (Schlumberger) | de Loubens, Romain (Schlumberger-Doll Research) | Chugunov, Nikita (Schlumberger Doll-Research)
Abstract In this paper, we present a novel method for in situ estimation of two-phase transport properties of porous media using time-lapse resistivity, pressure, and flow rate data from a permanent downhole Electrode Resistivity Array (ERA) and pressure, and a production logging tool. The primary objective of this Fluid Movement Monitoring (FMM) setup and experiment is to provide in-situ measurements required to determine multiphase flow properties, such as relative permeabilities and capillary pressures. Continuous monitoring of oil displacement by injected water in all the permeable zones was conducted in a carbonate reservoir in Saudi Arabia. The field experiment was divided into two stages:Selection of the well location, coring and logging, experimental setup and completion designs, cleanup, production profiles, pressure transient buildup tests, water injection and subsequent production of all injected water, and collection of all relevant data that include time-lapse pressure, production and injection profiles, and resistivity; and Interpretation of all the data acquired from different sources, development of algorithms/software to compute the movement of the injected fluid through the reservoir, and the inversion of multi-source and multi-physics measurements. This monitoring experiment was achieved through an integrated interpretation of different data sets such as transient drawdown/injection and drawdown/buildup tests, 3D deep resistivity, production and injection profiles, openhole log, and core measurements. This approach is new to the industry and the first field experiment for direct in situ determination of two-phase flow properties. The key outcome of this field experiment is a full verification of the permanent downhole resistivity array and pressure sensor experimental setup for estimating in-situ layer relative permeabilities and capillary pressure and monitoring water movement inside the formation. This allowed multiphase characterization of the formation around the measurement well to a radial depth of tens of meters.
- Asia > Middle East > Saudi Arabia (0.48)
- North America > United States > Texas (0.46)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Abstract The Messoyakha Gas Field is located in Siberian permafrost. The field has been described as a free gas zone, overlaid by hydrate layer and underlain by an aquifer of unknown strength. The field was put on production in 1970 and has produced intermittently since then. Some characteristic observations were increase in average reservoir pressure during shut-in, perforation blocking due hydrate formation and no change in gas-water contact. It is believed the increase in reservoir pressure was caused by the hydrate layer dissociation, rather than aquifer influx. The objective of this study is to use numerical model to analyze the observed production data from the Messoyakha field. In this study, a range of single-well 2D cross-sectional models representative of Messoyakha have been developed using Tough + Hydrate reservoir simulator. The simulation results were analyzed and compared with various field observations. Further, we have done a parametric study of reservoir properties of hydrate capped gas reservoir. We have used Tough + Hydrate to simulate the observed gas production and reservoir pressure data at Messoyakha. We simulated various scenarios that help to explain the field behavior. We have evaluated the effect of various reservoir parameters on gas recovery from hydrates. Our work should be beneficial to others who are investigating how to produce gas from hydrate capped gas reservoir. We were able to generate results that are very similar to the reported flow rates and pressure behavior in Messoyakha Field. The value of absolute permeability in the hydrate layer and the lower free gas layer substantially affects the continued dissociation of hydrates during shut-down. We also modeled the formation of secondary hydrates near the wellbore that can cause the reduced gas flow rates. The important parameters affecting the gas production are the formation permeability in the gas layer, the effective gas vertical permeability in hydrate layer, the location of perforations, and gas hydrate saturation. We have described various scenarios which are beneficial as well as detrimental in producing gas from hydrate capped gas reservoirs. We have also listed various parameters that should be carefully measured for accurate modeling work. Introduction Natural gas hydrates have been the subject of active research in the oil and gas industry since their role in blocking fluid flow in oil and gas pipelines was demonstrated by Hammerschmidt (1934). Later, Makogon (1965) proposed that naturally occurring gas hydrates could exist in the earth's subsurface. Since 1965, a number of research projects have been performed to estimate and quantify the volume of naturally occurring gas hydrates. Although there is uncertainty over the quantity and distribution of naturally occurring hydrates in the earth, there is general agreement that substantial volumes of gas hydrates do exist in nature (Sloan and Koh, 2008). According to the latest data gathered by various expeditions for hydrates, the gas resource in hydrate ranges from 105 to 106 Tcf (US Department of Energy, 2007). Natural gas hydrates (NGH) are crystalline compounds formed by the association of molecules of water with natural gas. NGHs are a subset of substances known as clathrates, which means "cage like structures". The formation of natural gas hydrates depends upon pressure, temperature, gas composition, and the presence of inhibitors such as salts. NGHs are found in the subsurface in two distinct types of settings. One is the permafrost in arctic regions and the second is in deepwater marine environments.
- North America > United States (1.00)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Tazovksy District (0.79)
- Geology > Geological Subdiscipline (0.93)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.87)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Gas hydrates (1.00)
- (2 more...)
Abstract Gas coning or channeling is a serious problem in many oil fields. It can reduce oil production significantly. Therefore, it is important to minimize excessive gas production. Production at high gas/oil ratio is a problem, which occurs because of the high gas mobility in the formation. Gels and foams have often been used to reduce gas movement into the wellbore of oil wells. Oil production from an oil producer in a carbonate reservoir declined due to excessive gas production. A detailed diagnostic work was conducted to determine the source and entry of gases into this well. In addition, several gelling systems were examined in the laboratory as a means for gas shut-off in this well. The results of several logs identified two zones for gas production. The first zone 6,000- 6,500 ft is responsible for 80% of the gases produced from well A. Another zone, 7,200 - 7,400 ft is responsible for the remaining gases. Several chemical means were evaluated for total shut-off of these two zones. These systems were compatible with formation brines. The gelation time can be controlled by varying the cross-linker concentration, or by injecting a preflush to cool down the formation. A surfactant system with a source of calcium was evaluated to be used for gas shutoff purpose. This system produced a precipitate that can be removed by toluene and other hydrocarbons. Introduction Field-S is characterized by low permeability reservoir overlain by a massive gas cap was initially developed in 1996 with one-km single lateral horizontal wells to effectively drain the hydrocarbon while reducing gas coning. The oil column in this field is overlain by a large gas cap, and underlain by an active aquifer. The temperature range of the formation is 180–195°F. The produced crude has °API stock gravity of 41 and a dynamic viscosity of 2.83 mPa.s at 70°F. Wells and production facilities are situated on the interdune subkhahs. The associated gas, representing an average gas oil ratio (GOR) of 750 SCF/STB, is separated, compressed to 3,500 psig, and re-injected into the gas cap. In terms of mineralogy, the formation is dominated by calcite (90–100 weight percent). The remaining minerals are minor dolomite (0–8 percent, occasionally reaching 13 percent in isolated intervals and trace amounts (usually less than 0.5 weight percent) of ankerite, quartz, pyrite, siderite and gypsum. Producing at high GOR is a concern in this field due to limitations of the gas handling facility. Gas production is caused by fractures and coning as a result of the high mobility of gas in the formation. Unwanted gas production in oil producing wells is a factor that limits the productive life of oil wells because they have to be restricted to minimize gas production. Laboratory and field studies can be used to develop a well treatment to reduce gas production in oil producing wells. The method is based on the placement of a chemical blocking agent into the appropriate zones. Gels have often been used to reduce gas coning in reservoir.1,2 Gas shut-off (GSO) using foam barriers has also been identified as a potential measure to control GOR downhole.3,4 The development cost of Field-S can be influenced by controlling the number and location of wells and the flow rate of each well. However, the flow rates are usually restricted when these wells encounter gas coning problems. Production from carbonate reservoirs with bottom water or gas cap is always associated with coning and/or channeling.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.83)
- Europe > Norway (0.68)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
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