Abstract The objective of this study is to develop an analytical model to calculate hydrate recovery and rate of gas generation when a hydrate-capped gas reservoir is produced at a constant bottomhole pressure. A similar model has been developed in the past for constant rate production. Such models are useful, when large number of sensitivity studies are necessary to evaluate the uncertainty in reservoir parameters and only limited specific properties of a hydrate reservoir are available. In this work, a tank-type material balance equation is considered. This is combined with the solution for the temperature of the hydrate cap to obtain the rate of gas generation during the period of constant bottomhole pressure production from a hydrate-capped gas reservoir. A numerical solution was used to validate the assumptions made to develop the analytical model; this numerical model relaxes some of these assumptions. The role of hydrate in improving the productivity and extending the life of hydrate-capped gas reservoir is demonstrated. The results show that the overlying hydrates can have a significant effect on improving the productivity of the underlying gas reservoir and increasing the reserve. Scope of the Study In this study we develop an analytical model to calculate hydrate recovery and rate of gas generation when gas is produced at a constant bottomhole pressure and decomposition occurs throughout the hydrate cap. For this purpose, a volumetric material balance equation is developed. The solution for the temperature of the hydrate cap is combined with the tank-type material balance equation and is solved for the rate of gas generation during the period of constant bottomhole pressure production from a hydrate-capped gas reservoir. In the following, after presenting the analytical modeling of the process, we perform a sensitivity study to investigate the effect of various reservoir parameters on reservoir performance, including the importance of porosity, thickness of hydrate zone, thermal conductivity and well bottomhole pressure. Analytical Model In order to obtain an analytical model to predict the recoverability of hydrate during constant bottomhole pressure production from a hydrate-capped gas reservoir, we assumed decomposition of hydrate occurs simultaneously throughout the hydrate layer. Four equations are used to develop the analytical model for predicting the behavior of the hydrate-capped gas reservoir during the period of constant bottomhole pressure production: Material balance equation Energy balance equation Hydrate decomposition model Inflow performance equation In the following, first the above mentioned equations are explained, and then the mathematical modeling of the process leading to the analytical model is presented. 1) Material balance equation: It is assumed that the pressure and temperature within the reservoir are instantaneously uniform; a depletion type material balance model can be used to predict the average reservoir pressure of the hydrate-capped gas reservoir. The simplified form of this equation for a volumetric hydrate-capped gas reservoir can be written as (Gerami et al., 2006): Equation (1) (Available in full paper) In the above equation, G p and G g are cumulative gas production and generation, respectively, and G f is the initial free gas-inplace.

Abstract A number of numerical simulation studies of gas hydrate reservoirs have indicated that the pressure reduction method known as depressurization is a promising technique to produce gas from hydrate reservoirs. In some cases, severe ice formation has been observed, leading to plugging and termination of gas production. Some researchers have suggested that if the flowing bottomhole pressure is not lowered beyond the equilibrium pressure corresponding to the freezing point of water, then ice formation may be avoided. This argument is based on the premise that the lowest temperature would occur at the wellbore. If temperature can be controlled to above zero by controlling the bottomhole pressure, then freezing should not occur. The objective of this work is to explore under what conditions ice particles form. Various cooling mechanism (cooling because of decomposition, gas expansion, etc) are studied in detail. For this purpose, a 3D mathematical model for gas production from hydrate reservoirs is introduced which incorporates energy balance, fluid flow and kinetics of the hydrate decomposition along with the ability to predict the formation of ice particles. This model is developed by modifying the GPRS (General Purpose Reservoir Simulator) platform to account for a number of mechanisms including hydrate decomposition and ice formation. GPRS is an object oriented reservoir simulator code developed at Stanford University. We will then apply this simulator to model largescale hydrate decomposition process in porous media, and demonstrate the effect of ice formation on gas production behavior. Through some case studies we investigate the conditions in which ice forms and becomes an issue. The learning for these studied are then used to suggest practical ways of avoiding ice formation. Introduction Hydrate particles are made up of natural gas molecules trapped in water molecule structures, and are considered as a potential resource for clean energy. Enormous quantities of methane gas exist in the form of hydrate in the permafrost and offshore environments. Large resources of hydrate have been explored worldwide including the North West Territories of Canada, Siberia, Alaska and Japan. In the last two decades much interest and research has been devoted towards the mathematical modelling of gas production from hydrate reservoirs. Three general techniques have been suggested to recover gas from hydrate reservoirs which are all based on breaking the stability conditions of hydrate leading to generation of gas; Depressurization, Thermal Stimulation and Inhibitor Injection. While depressurization does not require an external source of energy and is based on propagation of pressure drop from the wellbore to the hydrate decomposition zone, the thermal stimulation technique needs an external source of energy, not unlike those applied in the thermal recovery of heavy oils. Efficiency and economics of these techniques is the subject of numerous investigations. The first attempts to model hydrate formation and decomposition go back to the works done in the first decades of 1900's which aimed at preventing hydrate formation in the gas transportation pipes. Exploration of hydrate reservoirs and their potential as a new resource for energy has resulted in more research activities in the last two decades.

Abstract Gas hydrates are being considered as a future-alternate energy resource due to enormous quantities of natural gas deposition in hydrate form in the permafrost and offshore regions of the world. This study introduces an analytical numerical model for simulation of gas production by hydrate decomposition in porous media through depressurization process. Developments of several analytical and numerical models have been reported in the literature, however, mainly focused on decomposition processes. We coupled intrinsic kinetics of hydrate decomposition and heat transfer to analyze the production process. A commercial reservoir simulator was then used to construct a field scale model. A well is completed in the gas zone to follow the effect of depressurization in porous media and its effect on hydrate decomposition. Using the constructed analytical-numerical model a production strategy for a hydrate reservoir was designed. By use of this model the influence of different parameters related to formation properties, operating conditions, etc, on gas production may be predicted and evaluated. Introduction Natural gas hydrates in permafrost regions and offshore environments represents a potentially enormous supply of natural gas. This resource is expected to be an energy resource of the future. A portion of the gas hydrate reserves could help eliminate concerns of domestic energy shortage in the 21st century. Different estimations presented about the total energy reserves trapped in methane hydrates. The United States geological survey (kvenvoldsen, 1993) 1 estimated that the total amount of methane in gas hydrates around the world is approximately 7*10 5 trillion cubic feet (ft 3 ). According to Sassen 2 the resource potential of methane in hydrate exceeds the combined worldwide reserves of conventional oil and gas reservoirs, coal and oil shale. From technical view, the gas could be produced from the hydrate disociation by depressuriztion, thermal stimulation, inhibitor injection or a combination of these methods. The potential for gas production through different methods is still uncertain and under investigation. Developed models can be divided into two broad categories: analytical and numerical models. Analytical models are used for mechanistic studies and improve understanding of the process. Numerical models have smaller number of simplifying assumption, so they are more comprehensive. In this study, we focused on depressurizing method, where the pressure is decreased below the thermodynamic equilibrium pressure of hydrate. As previous studies mentioned, the heat transfer to the decomposing zone, intrinsic hydrate decomposition, and gas-water two phase flows are the three mechanisms involved in hydrate decomposition in porous media. Previous studies 3 showed the two first mechanisms are rate controlling in hydrate decomposition. So we used the analytical model to describe the heat transfer to the decomposing zone and intrinsic hydrate decomposition. Hoe and when after the production starts, the pressure decreases below the equilibrium pressure is a subject that studied more in this work. Analytical model Previous studies 3 showed that the rate of decomposition in controlled by the intrinsic kinetics of decomposition and the heat transfer to decomposing zone. So in this study these two processes are coupled to model the decomposition step.

Abstract Trident Exploration operates a significant portion of a Mannville-age coalbed methane field near Ft. Assiniboine, Alberta, Canada. This presently is the only commercial Mannville project in Alberta and currently produces about 90mmcf/d. The Mannville coals are wet and artificial lift is extensively used to dewater the coal seam. Well design has evolved throughout the project, starting with vertical wells and then progressing to horizontal and multilateral wells. Each design change has allowed significant production increases, but has also added to the challenge of economically lifting water. Electric submersible pumps and beam pumps are typically used. Rod driven PCPs were used in early stages of the project with limited success. A PCP driven by a downhole motor, or ESPCP, has successfully operated through a 6 month trial period. The ESPCP has shown potential to deal with problems caused by well design and problems inherent with CBM production. Introduction The Corbett Creek project is a wet coalbed methane development located near Fort Assiniboine, Alberta, Canada. Current CBM production is about 90 mmcf/d (2500 e3m3/d). The target formation is the upper Mannville coals, which exist over a broad area across central and southern Alberta. It is estimated that these coals contain more than 360 TCF (10.1 × 10 12 m3) of gas (1). Water saturation, gas content, depth, and other properties vary widely throughout the Mannville coals. In the Corbett area, the coal is from 840m to 1100m vertical depth. Two seams are targeted, one being an average of 3m thick and the other 2m thick. Seams are separated by 5m to 10m. Water is removed from the coal seams to reduce bottom hole pressure to a critical point where gas will begin to desorb from the coal. The greater the differential between the desorption pressure and the bottom hole pressure, the greater the amount of gas that will desorb. A pilot project was started in 2000 by Trinity Energy with three evaluation wells. Five more vertical wells were drilled over the next two years to continue evaluation of the area. Trident acquired the properties in 2002 and continued expanding the pilot by drilling 35 more vertical wells over the next two years. Horizontal drilling was introduced in 2004 to improve water inflow, accelerate dewatering and decrease the amount of time to initial gas production. Surface footprint was also significantly reduced. Results proved successful and 40 horizontal wells were drilled over the next two years. In July 2005, Trident and partner Nexen announced Corbett was the first commercial Mannville project in Alberta. In 2006, the multilateral well design was introduced to reduce drilling and artificial lift costs. One multilateral well replaced 3 or 4 single leg horizontals. Multiple seams could be drilled from one well. Gas rates per well also significantly increased and allowed some wells to free flow after an initial dewatering phase. (See CIPC Paper 2008–200 "Economics of Mannville CBM Development: Drilling & Production Innovation at Corbett Creek" by John Cockbill for more detail.)

Abstract The ES-SAGD process was developed to improve the energy and oil drainage efficiency of the SAGD process. The idea of the ES-SAGD process is to co-inject solvent with steam and the co-injected solvent mixes with the bitumen to further reduce the viscosity of the heated bitumen along the boundary of the steam chamber thus enhances the oil recovery. Practically, the coinjected solvent will be a solvent mixture (such as diluent /naphtha) due to its availability and reduced cost than a pure hydrocarbon. This paper reports the results of an ES-SAGD lab test conducted with steam and diluent co-injection using Athabasca bitumen. To simulate the ES-SAGD test, a pseudocomponent scheme to represent the complex solvent mixture in the numerical model is derived, based on the diluent composition and measured PVT data. The behaviors and effects of the co-injected solvent in the ES-SAGD process are analyzed through detailed history matching of the ES-SAGD test. Numerical sensitivity analyses are also performed to investigate the effects of some key parameters in the numerical approach. Introduction The Steam Assisted Gravity Drainage (SAGD) 1 and the Vapor Extraction (VAPEX) 2 , combined with the horizontal well technology, are being developed to recover the enormous heavy oil and bitumen resources in Western Canada. The SAGD process has been successfully field-tested and is in the early stage of commercial-scale application while the VAPEX process is still at the piloting stage. Both processes have their advantages and disadvantages. The advantage of the SAGD process is its high oil production rate. However the high production rate of the SAGD process is associated with intensive energy consumption and CO 2 emissions from burning natural gas to generate steam, and costly post-production water treatment. The VAPEX process, on the other hand, has the advantage of lower energy consumption and water usage, therefore less CO 2 emission and water treatment cost. However, the major drawbacks of the VAPEX process are its relatively lower oil production rate and the additional cost of solvent. The ES-SAGD process was developed 3, 4 to improve the energy efficiency of the SAGD process by combining the advantages of the SAGD and VAPEX processes. In the ESSAGD process, small amount of solvent, pure hydrocarbon (i.e. hexane) or hydrocarbon mixture (diluent), is co-injected with steam. The basic idea is that as the solvent flows with steam along the boundary of the vapor chamber, it dissolves into and mixes with the bitumen, hence reducing the viscosity of the bitumen and further enhances the oil recovery. Practically, the co-injected solvent will be a hydrocarbon mixture (such as diluent /naphtha) due to its availability and reduced cost than a pure hydrocarbon. Thus the study of the impact of the different components in the hydrocarbon mixture in the ES-SAGD process becomes important. In this study, one ES-SAGD lab test with Athabasca bitumen and a field solvent mixture (diluent) as the co-injected solvent using a 2D high-pressure/high-temperature test facility was conducted. The ES-SAGD test was numerically history matched.

Abstract In this study, we have investigated a gas production system from methane hydrate layers using hot water injection using horizontal wells including a production well and multiple injection wells. Experiments on the gas production were performed using scaled two-dimensional physical models to investigate fluid flow characteristics and production performance. Furthermore, experiments on an improved production system by hot water injection using multiple injectors have been carried out. It has been shown that gas production rate can be improved by hot water injection using the multiple horizontal injectors compared with that with a single horizontal injector for thick hydrate layers of over 15 meters. The numerical simulations have been done on the field gas production performances by hot water injection with multiple injectors which are drilled in a hydrate layer of 15 meters in thickness. The cumulative gas production for three years with 1000 ton/day of hot water injection was evaluated at the end of three years as 8?10 6 std m 3 . The system using multiple injectors is appeared to be more economical procedure than that with the single injector. Furthermore, a synthetic gas production system has been presented in considering of a gas turbine combined thermal cycle which can provide dissociation heat of methane hydrate by waste heat of its exhaust gas. Introduction Recent studies confirm that conserved methane hydrate deposits in sedimentation layers at a depth of more than several hundred meters from the bottom of the sea floor can be utilized as novel natural gas resources. In situ hydrate decomposition into water and gas is required to produce methane gas economically from these layers, since methane hydrate is a type of non-mobile solid energy resource. To trigger methane hydrate decomposition, decompression or temperature increase out of the equilibrium zone is necessary, while heat should be supplied for continuous dissociation. Accordingly, new gas production systems that supply heat continuously into the methane hydrate layers have been reported. The conventional methods of gas production to date include depressurization, inhibitor injection, and thermal recovery. Gas production by the hot water injection system is advantageous compared to depressurization (Kmath et al., 1991) and inhibitor injection in that the dissociation speed of methane hydrate and gas production rate may be relatively low due to a lower heat supply rate. On the other hand, the hot water injection method using vertical wells requires drilling with high density into the targeted area (Masuda et al., 2002), since methane hydrates are formed in sand layers with very low permeability. In this paper, a hot water injection method using horizontal wells consisting of a producer and multiple injectors is proposed. Hot water is injected into the hot water chamber formed in the hydrate layer from a lower horizontal injector. Gas and water are continuously produced from the upper horizontal producer. Physical models and numerical simulations have been carried out to determine the production performance of the present thermal recovery system and numerical modeling with STARS ™.

Abstract The purpose of this work is to model the single-phase radial gas flow in coalbed methane including equilibrium sorption phenomena in the coal matrix and Darcy flow in the natural fracture network. Considering a control volume, the gas desorption rate as a function of time and space is incorporated into the radial continuity equation as a source term. Using Langmuir type sorption isotherm, gas desorption rate is determined at any radius of the reservoir. Introducing the definition of pseudo-pressure and pseudo-time, the resulting continuity equation is converted into the linearized diffusivity equation by modification of total gas compressibility. It is shown how the traditional definition of the material balance pseudo-time is modified for dry CBM reservoirs. With the help of these transformations, the traditional (PTA and RTA) type curves can be employed for analysis of production data of dry CBM reservoirs. The model developed here is validated against Fekete's numerical CBM simulator over a wide range of reservoir parameters. In addition, one set of field data from Horseshoe Canyon coals of the Western Canadian Sedimentary Basin is analyzed using the solution procedure presented in this paper. Introduction Coalbed methane (CBM) is a natural gas produced from coal seams. Coal is both the source rock and the reservoir for methane production. The world total CBM resource potential is evaluated at about 143.2 trillion cubic meters. (1) CBM reservoirs are naturally fractured reservoirs that are characterized by two distinct porosity systems including: micropores (matrix) with extremely low permeability and macropores (natural fractures or cleats). Due to the small pore diameter of less than 10 °A, the coal matrix has a large internal surface area of 100 to 300 m 2 g. (2,3) As a result, substantial quantities of gas can be adsorbed on the surface of the coal grains. Micropores are impermeable to gas and inaccessible to water. However, the desorbed gas can transport through the primary porosity system by diffusion. The macropores acts as a sink to the micropores and provide permeability to fluid flow. In porous media with larger pore size distributions, mass transfer is driven by pressure gradients, whereas in coal, mass transfer is driven by concentration gradients. The diffusion through the micropores can be the result of three distinct mechanisms that may act individually or simultaneously (4) : bulk diffusion, where molecule/molecule interactions dominate; Knudsen diffusion, where molecule/surface interaction dominate; and two-dimensional surface diffusion of the adsorbed gas layer. The steady state diffusion coefficient for most coals is on the order of 10 −4 to10 −5 cm 2 s and the transient diffusion coefficient ranges from 0.5 to 10 times the steady-state values. (4) These experimentally determined diffusion coefficient represents averaged values including the contributions of the bulk, Knudsen, and surface diffusion processes. Diffusion effects can be quantified by determining asorption time. The sorption time is equal to the time required to desorb 63.2 percent of the initial gas volume (It is determined from whole core canister desorption test). This time is related to fracture spacing and the diffusion coefficient. (5)

Abstract Main objective of this study is dealing with a real case study of an Iranian gas condensate reservoir for the purpose of underground gas storage. Doing such a study in this reservoir will aid developing this technology and also demonstrates new concept of underground gas storage in partially depleted gas reservoirs. After gathering some data about the reservoir and preparing a geological model for the field, a simulation plan considered for this field. Static model converted to a dynamic one by assigning reservoir fluid data. Finally, compositional model of the reservoir prepared and verified to be accurate through a history matching process. After being sure about accuracy of the model and validating it, different scenarios for underground gas storage developed. Depletion and gas storage scenarios made for the field and results obtained. Gas storage in partially depleted gas reservoir considered in scenarios for developing this field too. After comparing different scenarios some practical results achieved and best scenario for developing this field chosen. Introduction An underground gas storage system can be defined as a combination of a constant supply with a variable demand for economic advantages [1] . In other words, it helps to combine low-demand summer season and high-demand winter season. The whole process is injecting natural gas or rarely other gases into subsurface reservoirs in the periods that demands fall bellow the gas supply. When demands exceed the supply, the gas will be withdrawn from the reservoir. Fluctuating demands due to temperature and climate make it an economic process that is necessary in many cases for efficient use of the pipelines. It also helps to have an effective delivery during peak demand seasons. This process can also help producing oil or condensate and can be considered as an IOR method too. By increasing demand of gas in many areas of the world, developing storage plans and effective use of existing storage sources is a priority for engineering and economic advantages. Figure 1 illustrates natural gas supply and demand relation and clarifies importance of having some gas stored in low demand periods in order to use in high demand periods. Figure 1- Natural gas supply and demand. (Source from [2]) (Available in full paper) Depleted gas reservoirs called to be the best choice of underground gas storage and almost all early projects were developed in depleted gas reservoirs. There are of course other types of underground gas storage that are storing gas in aquifers and in caverns and salt structures. Peak load natural gas consumption has become a problem in big cities in Iran, especially in Capital. Underground gas storage technology seems to be a helpful key to overcome this trouble. Reservoir Summary A gas condensate reservoir is chosen for the purpose of underground gas storage that is located in central Iran. This field discovered in 1955 and its production started in 1959. It has a structure that is a northwest-southeast trending anticline approximately 25 kilometers long and about five kilometers wide. The structure is investigated by surface and seismic surveys and eight wells drilled on the field.

Abstract As part of the activities of the Conoco Phillips Chair in Tight Gas Engineering in the Chemical and Petroleum Engineering Department at the University of Calgary, a comprehensive literature review has been conducted that has led to our understanding of the current status on the study of tight gas sand formations. This paper presents the results of that work concentrating initially on Canadian and U.S. tight gas sands. Next, we will examine these types of formations throughout the world. The resource base of tight gas sands is estimated to be between 90 and 1500 trillion cubic feet in Canada. The resource base around the world has been estimated at some 7500 trillion cubic feet. The literature survey discussed in this paper is the basis for the mission-oriented research on tight gas reservoirs conducted at the University of Calgary. This research looks at refining the resource base and recoveries from tight gas in Canada and finding economic means of extracting as much of this gas as possible. The planned research program will be presented. It is expected that the research program will result in the delivery of highly qualified professionals, with significant knowledge of tight gas formations, needed by industry and research organizations. In addition, it is likely that the research results will prove to be of value in other parts of the world, and will be exportable, creating business opportunities for Canadian companies. Evaluating the current status of geologic models, reservoir characterization, recovery and production technologies currently available for these types of formations is the first step in the effort to reach the final goal: finding economic means of producing as much of this gas as possible. Introduction Tight gas production is not reported in Canada. However, the interest in this resource is growing significantly. For example, a quick search in the SPE website using the words "tight sands" resulted in 5842 publications as of March 14, 2007. Obviously our goal in this survey paper is not to list everything that has been published in the literature but to highlight what we consider key issues in the evaluation and commercialization of tight gas sand production. Tight gas sands are part of what is usually known as unconventional gas which also includes coal bed methane, shale gas and natural gas hydrates. Tight gas sands have been defined in different ways by different organizations but a unique definition has proven elusive. 1 The original definition dates back to the U.S. Gas Policy Act of 1978 that required in-situ gas permeability to be equal to or less than 0.1 md for the reservoir to qualify as a tight gas formation. 2 At present this is probably the most commonly accepted definition. A second U.S. legal definition indicates that in a tight reservoir an average sustained un-stimulated initial gas rate is less than the maximum specified for a given depth class. However, it is important to understand that, although convenient, not only permeability and/or depth play a role in gas production from tight gas reservoirs.

Abstract About 200 000 infill/step-out wells have been drilled in the Western Canadian Sedimentary Basin (WCSB) since 1980. This wealth of data implicitly included clues to various reserve characteristics but techniques for evaluation were not obvious to us. We tried different ways of processing data for deriving meaningful insights. In this paper we present some of these with appropriate examples. Pools were grouped by major formation type, fluid type, and depletion mechanism. The distribution performances of various sub-groups were individually evaluated. Where possible, performances of horizontal and vertical wells were treated separately. We also compared the value of the Average and the Median performance parameters. In most cases the average was much larger than the median. We prepared frequency plots and their representation on the normal (standard deviation) scale for the wells in each group. From these plots we were able to characterize the lateral heterogeneity of the reservoirs. This could be used in applying risk factors to future projects. Risk analysis can also be aided by other features of frequency distributions for corresponding wells. A rate-cumulative production plot was also helpful in determining acceleration benefits and incremental reserves resulting from infill drilling. Introduction Two hundred thousand infill and step out wells were drilled in the WCSB between 1980 and 2005 (Table 1a). Infill wells for oil and gas were approximately equal in numbers. About 75 percent of the wells were drilled in sandstone formations and 25 percent in carbonate formations. Overall, 50 000 wells were drilled in sandstone heavy oil reservoirs and 80 000 in sandstone gas reservoirs. Of these, more than 50% were shallower than 500 meters. In this paper we focused mainly on the performance of infill wells in mature light oil carbonate reservoirs. First, we reviewed the performance of two Mississippian pools in SE Saskatchewan (Williston Basin). Here, the horizontal wells performed noticeably better than the contemporary vertical infill wells. In Alberta however, in the three carbonate pools reviewed, two oil pools and one gas pool, the vertical infill wells performed better than the horizontal wells. (In the case of the Swan Hills BHL pool the difference was small) We also reviewed the performance of a heavy oil sandstone reservoir and a shallow sandstone gas reservoir. In both pools, the horizontal infill wells performed better than the vertical wells. A major objective of this paper is to show how a relatively simple statistical analysis of the performance curves could provide useful insights; and also, to present a method to qualitatively/quantitatively characterize the lateral heterogeneity as well as, risks in developing similar pools by infill drilling. In addition, we also illustrate how the oil rate-cumulative production plot could be used to identify contributions due to acceleration and incremental recovery. We have incorporated some of the ideas discussed in previous papers 2–8 . METHODOLOGY Our main data sources were the provincial Oil and Gas Reserves Books. Production data were obtained from a commercial data base. An "in-house" Excel based statistical program was used for analyzing/sorting the data and developing various statistical parameters, tables and graphs.

Abstract Fractured gas shale reservoirs in the Western Canadian Sedimentary Basin (WCSB) are often overlooked as a result of low initial production rates relating to vertical wellbores that have failed to intersect common vertical fracture sets. A recent study of the shale gas potential in WCSB has indicated there is a large resource potential for shale gas, with greater than 86 tcf of gas in place within Devonian through Cretaceous age shale formations. Furthermore, there is emerging evidence to suggest that shales have been contributing to conventional production. This paper will describe the major challenges of developing a commercial scale shale gas project including: Identifying geologic sweet spots, which meet the following criteria: Organic rich Thermally mature Marine to transitional marine Comparatively thick, and most importantly Permeability enhanced by fracturing or higher permeability interbedded facies Acquiring a large lease base capable of placing large numbers of wells, Designing and field-testing cost-effective drilling, completion, and stimulation procedures that are suited for the specific type of shale gas resources which are essential to the economic success of the project, and Continuous technology improvement and innovation including the use of state-of-the-art fracturing technologies such as micro-seismic to improve well productivity. Examples of a Canadian shale gas field pilot will be discussed to illustrate these key steps, which are critical to developing a successful commercial project. Introduction Fractured shale reservoirs include some of the oldest known oil and gas production in North America. Natural gas was produced from the Devonian shales near Fredonia, NY as early as 1821, which pre-dates any known oil production by almost 40 years. By 1926, the Devonian Ohio shale of the Appalachian basin was in commercial production and was the largest known gas field in the world (1). This area currently contains the majority of shale gas wells in the US, with over 30,000 gas wells producing in the order of 120 bcf/year (2). Fractured shales are differentiated from conventional reservoirs in that they are often both the source rock of the oil and gas, as well as the reservoir itself. The majority of the hydrocarbons are stored within the low permeability matrix rock of the shale reservoir, and a system of natural fractures provides the bulk of the transmissibility (permeability) within the reservoir. The size, extent, interconnectivity, and degree of cementation of the natural fractures typically dominate the overall productivity of the shale reservoir (3). Gas shale reservoirs are classified as continuous type natural gas plays: that is accumulations that are pervasive throughout a large geographic area that offer long-life reserves with attractive finding and development costs (4). Most shale reservoirs have very low matrix permeability (nano to microdarcy level) and require the presence of the extensive natural fracture systems to provide and sustain commercial gas production rates. Natural gas is stored in three ways: as free gas within the rock pores, adsorbed gas on the organic material, and as free gas within the system of natural fractures.

Abstract Gelled hydrocarbon has been used as a fracturing fluid from the early days of fracturing. Its use internationally has been prevalent; and continues to the present day in Canada, South America, Russia and East Asia. The paper will discuss the use of gelled oil fluids in Canada, particularly in lowpressure tight gas wells, where the use of CO 2 energized gelled hydrocarbon fluids have been very successful. The chemistry of these fluids and their application is discussed. The energized fluids have been used varied formations with permeabilities from 0.1 mD to 10 D, depths in excess of 3000 m and BHT from 10 to 110 °C. Initial and longer-term production data from wells treated with the energized fluid will be compared to wells treated with conventional gelled hydrocarbon fluids to show the effectiveness of the system in tight gas applications. The case study will include wells treated and producing from the Rock Creek oil, Dunvegan, Glauconite and Belly River gas formations in the Western Canadian Sedimentary Basin (WCSB). Observations on proppant selection and in-situ closure stress are made in addition to the fracturing fluid selection. Introduction Natural gas currently accounts for 22% of world wide energy consumption. As worldwide use of natural gas is increases to meet energy demand, interest in unconventional gas increases. This includes coal-bed methane, tight-sand gas, shale gas and gas hydrate wells. Commercial production of unconventional gas is still in its infancy with development of tight gas, coal-bed methane and shale gas performed mainly in North America. Resource assessment data of unconventional gas varies widely; however, it is universally accepted that the unconventional gas resource base, excluding gas hydrates, is more than twice that of conventional gas. Gas hydrates are excluded due to limited technology and success at developing the resource. In North America, gas resource from tight sands is estimated to be around 1371 Tcf (1). Unconventional gas production was only 1 Tcf / year in the 1970s, but has increased to around 4 Tcf / year in 1997 which accounted for 20% of the national gas consumption (2). Almost 70% of unconventional gas production is from tight sands. The definition of tight gas is somewhat arbitrary, but is generally accepted to mean from formations with an average air absolute permeability less than 20 mD. In-situ permeabilities in these types of reservoirs are generally less than 1 mD and can range down into the micro-Darcy range (10 –6 D) in many cases. Using appropriate drilling, completion and in some cases large-scale fracturing techniques, operators have succeeded in obtaining economic production rates from formations exhibiting in-situ matrix permeabilities as low as 10–6 D. In many cases, gas may exist in such low permeability formations, but its production is challenged due to adverse capillary forces, high in-situ saturations of trapped water, and in some cases, the presence of liquid hydrocarbons. If these saturations are too high, economic production from the zone is difficult without appropriate fracturing techniques. Tight gas reservoirs are susceptible to formation damage during drilling and completion operations. Low permeability formations tolerate only minimal damage.

Abstract In the last ten years, substantial progress has been made in the theoretical treatment of gas dissolution in water, near the critical point of water (374 ° C). An asymptotic behaviour of Henry's law for a variety of gases (the noble gases, methane, ethane, nitrogen, oxygen, carbon dioxide and hydrogen sulphide) already governs the behaviour of these gases at temperatures above approximately 180 ° C, well below the critical point. This behaviour has been used to develop a theory of gas production in SAGD, according to which gas production in SAGD largely occurs via dissolution of gas in the steam condensate. Further recent developments in this area of solution thermodynamics have extended the knowledge of this phenomenon to various light hydrocarbons, from butane to dodecane, and the aromatics such as benzene and toluene. In the present paper data for the distribution coefficients (K-values) of light hydrocarbon solvents in water are presented, and the application for prediction o solvent returns in SAGD enhanced by solvent co-injection is discussed. Optimal choice of solvent composition to maximize solvent returns is possible. Introduction In 2001, Thimm 1 proposed that gas production in SAGD proceeds via a mechanism whereby gases are dissolved in the produced liquids, and enter the wellbore in that form. No case has been reported so far where it has been necessary to postulate free gas entering the SAGD production well in order to explain the observed GOR and produced gas compositions. Gases are considered to separate from the liquids in the wellbore and facilities. The solubility of gas in a liquid is governed by Henry's Law, which may be stated as (Equation 1) (Available in full paper) The Henry's Law constant is related to the more conveniently used distribution coefficient, (Equation) (Available in full paper) as is self-evident from inspection of equation (1). In 1989, Japas and Levelt Sengers 2 provided the theoretical basis for observations made at that time and since, that the distribution coefficients for gases in general, for all solvents-gas pairs, declined as the critical point of the solvent was approached. In fact, Japas and Levelt Sengers showed that al values of K approach unity towards the critical point. In the case of water, this asymptotic behaviour governs gas solubilities above 180 ° C or so, and considerably earlier in the case of some gases. Harvey and Levelt Sengers 3 published a power law for a variety of gases in water, valid between the triple point and the critical point of water: (Equation 2) (Available in full paper) For the case where the solvent is water, all values of density, and also the fugacity term, in this equation may be found in or derived from steam tables. The values of A, B and C are published by Harvey and Levelt Sengers. Other authors have published coefficients of the same kind, notably Suleimenov & Krupp 4 for hydrogen sulphide. Thimm 1 has shown that this approach, when applied to simulated oil and water production forecasts in SAGD, or to actual production data, yields GOR and produced gas composition data in good agreement with actual results.

Abstract As our industry focuses more on natural gas production and on wringing the last drop of value from each property, it has become increasingly important to properly characterize and predict the solution gas performance from our oilfields. This paper will review historical techniques for predicting solution gas production under various common process mechanisms including depletion, weak and strong water drive, gas-cap drive, and production of a volatile oil. The paper will also discuss situations where numerical simulation may be required instead of using standard analytical techniques. The paper will present examples from the Western Canadian Sedimentary Basin that illustrate solution gas performance under each of the drive mechanisms mentioned above. Results are displayed using the "equal-value" concept, which shows the progress of each oilfield from its early life where revenue is dominated by oil sales to its later life when revenue becomes increasingly dominated by solution gas production. Introduction to the Problem The prediction of solution gas production is often taken for granted in oilfield forecasts, but is a multi-faceted problem when one considers the many components that impact the process (fluid and rock properties, interactions between fluids/rocks, geological properties, drive mechanisms, wellbore conditions, etc). Years ago, accurate predictions of solution gas volumes were less important because there was little or no value associated with the product. Today, the value of natural gas is essentially the same as oil on a heating value basis, so much more attention is paid to the prediction of solution gas volumes. Further, environmental pressures are driving government and industry to conserve all produced gas; and obviously it is important to understand how much gas will be produced to ensure installation of the appropriate conservation scheme. On its face, solution gas prediction is a deceptively easy problem: pressure declines, gas evolves from the oil, and is produced. So, if one completely understands the production mechanism and can accurately predict future pressure decline, and understands the PVT properties that govern the release of solution gas, and knows the rock properties that govern the trapping and flow of gas, and has a good picture of the overall geological model, then it can be fairly simple to predict solution gas production. Further, the interplay between these factors can result in non-unique solutions. Since the primary focus is mostly on oil volumes, appropriate attention is not always paid to the variables that govern solution gas production. The most common analytical methods for predicting solution gas production were developed by Tarner (Ref. 1) and Muskat (Ref. 2). These methods use material balance principles and a dynamic producing GOR to predict reservoir performance at pressures when the gas saturation exceeds the critical gas saturation. However, a number of simplifying assumptions were made in these analytical treatments, including thin horizontal reservoirs with negligible gravity forces (ie. no gas percolation). Other analytical approaches have been proposed that mitigate concerns with the Tarner and Muskat methods; however, all analytical methods have their own limiting assumptions.

Abstract In the last two years, there has been increased interest in low pressure SAGD operations, in part due to the gas over bitumen resource conflict. In an earlier paper it was predicted that low reservoir steam pressures had the effect of sharply reducing hydrogen sulphide and carbon dioxide production per barrel of oil. Likewise, particularly troublesome scales, such as the magnesium and calcium silicates, were less thermodynamically favoured than at high steam pressures. Further investigations into the fate of gases in SAGD have been undertaken, especially for the case where the virgin pressure of the reservoir is low. In such cases, the amount of solution gas is limited, and the bitumen at steam zone pressure is often undersaturated with respect to the available methane. The polar gases, hydrogen sulphide and carbon dioxide, on the other hand, are almost entirely produced via dissolution in the produced water. In the low virgin pressure case, the methane is entirely produced via dissolution in bitumen. This contrasts with initial reservoir pressures of, for example, 3500 kPa, where more than half of the methane is also produced via the produced water. The other major difference is that, in the low virgin pressure case, very little gas is predicted to accumulate in the steam zone. The implications of this work include an effect on simulation studies of bitumen production, and on the possible effect of cap gas production via the produced water. This may be an equity issue in the Athabasca area where cap gas has been shut in by regulatory intervention. Introduction There has been considerable interest in the issue of SAGD steam zone pressure (or temperature) in recent years. The issue revolves around the range of pressures under which a given SAGD project might be operated, without serious adverse economic effects on the project. Chhina 1 is reported to have advocated the use of lower pressures in order to reduce steamoil ratios (SOR), and therefore production costs. The issue has been further explored by Kisman 2 , who defines low pressure SAGD as involving "pressures below what steam/gas lift can accommodate, and above pressures where low-pressure consequences such as reduced oil rates and artificial lift difficulties affect the viability of SAGD operations". One of Kisman's conclusions was that operation at reasonably low pressures provides savings due to reduced SOR, and the smaller production well liners and tubulars that are needed. While there are limited field data on low pressure SAGD at present, the issue has received more detailed attention in the last few months owing to the ongoing gas-bitumen resource conflict. A previous paper 3 explored a number of aspects of the engineering chemistry of SAGD, which are also dependent on the pressure (i.e. temperature) of the steam zone. In the author's experience, these aspects have had significant impacts on some field operations. The engineering chemistry considerations pointed to potential benefits of operating SAGD at low pressure. The benefits included a possibility for avoiding the need for sulphur recovery, and reduced probability of mineral scales that have plagued some SAGD projects.

Abstract In recent years, substantial progress has been made in the theoretical treatment of hydrocarbon dissolution in water, near the critical point of water (374 ° C). At these temperatures, water becomes a solvent for gases including the lower hydrocarbons, and possibly higher hydrocarbons. The SAGD process is currently the only viable method for in-situ recovery of Canada's Athabasca oil sands deposit, a deposit of high viscosity oil in unconsolidated sand. Recent studies have sought to understand modifications at lower steam pressures and gas injection. Most recently, the idea of solvent co-injection has been under discussion. In the present paper, the predictive capabilities that have been developed for gas production in the SAGD process are studied in conjunction with the chemical kinetics and mechanisms of solvolytic reactions. The reactions that produce hydrogen sulphide and carbon dioxide, generally referred to by the name "aquathermolysis", are in fact solvolytic reactions by their nature. The results of this work suggest strongly that the production of the acid gas gases, hydrogen sulphide and carbon dioxide, will be suppressed in SAGD operations if a solvent is coinjected. The work has implications for the need for sulphur recovery plants in SAGD projects that are considered for solvent co-injection. Introduction In 2001, Thimm 1 proposed that gas production in SAGD proceeds via a dissolution mechanism. Gases are dissolved in the produced liquids, and break out of solution in the wellbore and facilities. There has been no case reported so far where it is necessary to assume free gas production in SAGD in order to account for observed gas production or composition. The rationale is as follows: The distribution coefficient (K-value) of a solute gas in equilibrium with a solvent is given by Equation (1) (Available in full paper) where yi and xi are the mole fractions of solute i in the gas and liquid phase respectively. Henry's Law may be stated as Equation (2) (Available in full paper) In this form, the unit of the Henry's Law coefficient is that of pressure, as is evident from inspection. For the purpose of this work, all Henry's Law constants are given in units of mPa. The equation shows that the K-values are related to the Henry's Law constant. Determination of Henry's Law Constants Henry's law coefficients for gases in solvents normally follow a power law known as the Valentiner equation T, T(2), T(3), However, at elevated temperatures, this equation begins to fail at about 175 °C, and could only be used for the lowest steam pressure situations. Above this temperature, deviations become progressively larger, because an asymptotic behaviour of the Henry's Law constant near the critical point of water makes an increasingly important contribution. Above °1750C, the specific volume of water begins to fall significantly from the normal 55.56 mole/L, and Harvey and Levelt Sengers2 have shown a linear relationship between Equation (3) (Available in full paper) in the range °1750C and the critical point of water at °3740C.

Abstract Water-drive gas systems are economically important but gas recovery may be limited by water loading of the production string or incomplete sweep in the reservoir. Efforts to improve recovery from water-drive gas wells have focused on limiting the completion length. However, limiting the completion interval decreases the gas production rate and may have a substantial negative effect on project economics. The effects of limited completion length on gas rate, cumulative gas production, and discounted revenue stream are considered for a range of reservoir and economic factors in this study. A multilevel factorial design in 8 factors (576 simulations) was analyzed using response models and Monte Carlo simulation. The gas price, discount rate and initial reservoir pressure are the most important factors affecting present value, followed by horizontal and vertical permeability and completion interval length. Because decreased completion interval length has a strong negative effect on gas rates and economics, methods that control water completion while maintaining longer completions are desirable. The completion length can be optimized using response surfaces and Monte Carlo methods. The optimum completion length depends on the distribution of the uncertain factors; computing the optimum at factor mean or median values is not equivalent and is less reasonable. Methods to address this uncertainty are presented. For the models considered in this study, productivity is often the most important factor and the expected project value is often maximized by using the maximum completion interval length. PROBLEM STATEMENT The behavior of gas wells under water drive has been investigated from many perspectives, from material balances (1,2) to detailed studies of completions. (3) These studies recognize a tradeoff between the additional drive provided by water influx versus the potential for gas trapping behind the advancing gas-water contact. In general, this has led to the conclusion that higher gas production rates are preferred to minimize trapping; the occurrence of a water-drive is widely perceived to lead to decreased ultimate recovery. Minimization of gas trapping is the motivation for schemes that produce water from the aquifer concurrent with gas production. (4) On the other hand, some studies have suggested that reservoirs with low gas productivity may benefit from water drives and indeed water injection may be advisable. (5) Because gas wells may not be able to produce with high water cuts, operators sometimes use partial completions to reduce coning and delay water loading. However, because the gas mobility is high, this strategy may be unnecessary and may decrease gas rates with little impact on ultimate recovery. (3) Partial penetration decreases productivity via a pseudoskin effect;(6) the attendant increase in near-well velocity exacerbates non-Darcy flow effects if the Reynolds number is greater than one. (7,8) In summary, the dependence of recovery on aquifer strength, reservoir properties and completion properties is complex. Although water influx traps gas, it sustains reservoir pressure; although limited completion lengths suppress coning, they lower well productivity. These tradeoffs can be assessed using numerical simulation and discounting to account for the desirability of higher gas rates. This study examines the factors that control the value of water-drive gas wells and proposes methods to analyze and optimize completion strategy.

Abstract Gudao shallow gas field has been in later production period. In order to improve the development results, researches of reservoir characterization and enhancing gas recovery were launched in 1997. Utilizing technical measures including geology, geophysical, logging, gas reservoir engineering and stratigraphic correlation etc., original gas in place (OGIP) is recalculated and evaluated. On the basis of production characteristics analysis, distribution of remaining gas is made clear, and potential targets are put forward. The major results are as follows. 1. Substrata are re-divided utilizing sand tracing technique and secondary logging interpretation. 2. Cognition of some gas sands being not connected mutually is turned via stratigraphic re-correlation, thus contradictions of unbalanced reserves-production relationship and lower formation pressure of new wells than normal pressure are solved. 3. Change rules of output and pressure for various kinds of reservoirs are investigated, and main factors influencing recovery efficiency are analyzed and respective ways for enhancing recovery efficiency are brought forward sequentially. 4. OGIP is recalculated using pressure drop method (p/z-Gp) to verify results of volumetric method further, which can explain why recovery efficiencies of some reservoirs exceeded 100% before. 5. Based on break-even analysis, economic limit reserves for different kinds of reservoirs are computed, and overall adjustment plan is submitted, in which 12 wells have been brought on stream with gas rate of 107 × 10 3 m 3 /d. Incremental producing reserves in place are 508 × 10 6 m 3 with recoverable reserves 305 × 10 6 m 3 , and favorable economic benefit has been seen with predictable production value about RMB 1,700 million Yuan. Thirty-five backup reservoirs are found as well, which provides dependable foundation for the future, and overall recovery efficiency predicted could be advanced for more than 5% and gas production decrease has been relieved. The results could provide certain directive meanings for gas fields of similar type. Introduction The main purpose of reservoir characterization in later production period is to study the distribution rules of remaining gas, which has especial significance on maintaining field stable production and improving recovery factor. 1–4 Research of remaining gas distribution is based chiefly upon deepening understanding to reservoir geology, so as to find potential abundance areas of remaining gas, combining with analysis to performance data. 5–8 In Shengli Oil Fields, Gudao shallow gas field is one of the earliest gas fields put into production, as well as the biggest gas field among fields discovered presently, with cumulative gas production being 15% of that of Shengli approximately. Put into production in 1976, the field has been into later production period. Along with recovery percent of OGIP increasing, formation pressure declines year after year, and shut-in or low-deliverability wells increase with sand and/or water production being serious. In late 1996, there were only 14 gas wells producing normally among 46 wells, with gas rate of 71.3 *103m3/d (per-well gas rate 5.1 ??103m3/d only). Annual gas production was 6919 × 10 3 m 3 with a decline rate up to 21.8% in 1996. In order to improve production results, research of gas reservoir characterization and enhancing recovery factor was launched in 1997.

Abstract Gas hydrates as a significant resource of natural gas have attracted considerable attention in the recent years. However, the severe environmental conditions of gas hydrate reservoirs and the solid form of hydrates require extensive technological development and expertise before commercial gas production becomes possible. Numerical studies often give useful information in predicting the potential and economic viability of a recovery process. This paper presents a 2-D cylindrical simulator for gas production from hydrate reservoirs. The model includes the equations of gas-water two-phase flow, conductive and convective heat transfer, and intrinsic kinetics of hydrate decomposition. The simulator is used to model a hydrate reservoir where the hydrate-bearing layer overlies a free gas zone. A well is drilled and completed in the free gas zone. Pressure reduction in the free gas zone leads to the decomposition of the overlying hydrate and subsequent production of the generated gas. In this paper we investigate the effect of various parameters on gas production behavior. In particular, these parameters relate to formation properties, operating conditions, kinetic parameters etc. The cumulative gas generated and produced, pressure, temperature and saturation distributions are studied for the different conditions. The potential of gas production from formations containing gas hydrates is analyzed using the results of the sensitivity study. Introduction Today, increasingly more stringent environmental considerations require that clean sources of energy be found. It is, therefore, anticipated that the demand for natural gas will continue to increase significantly. The gas hydrates, which are made of water and natural gas (mainly methane) and exist in enormous quantity, are being considered as a potential source for natural gas production. However, the technologies for recovering natural gas from hydrates are very challenging, and are still under development. Sloan[1] has presented an extensive review of some suggested methods including depressurization, thermal stimulation and inhibitor injection. The least energy intensive process is thought to be the depressurization method, since in this method the heat of decomposition is provided by the surrounding formation. Modeling of gas production from hydrate reservoirs involves solving the coupled equations of mass and energy balance. A review of analytical[2–6] and numerical[7–14] models suggests that two approaches with respect to conditions at the decomposition zone have been taken: equilibrium and non-equilibrium. In the equilibrium models, the three-phase hydrate-gas-water interface is at equilibrium. The underlying assumption in these models is that the intrinsic rate of hydrate dissociation does not control the process, and the overall rate of hydrate dissociation is controlled by other factors such as fluid flow or heat transfer. In non-equilibrium models however, the hydrate-gas-water interface is not at equilibrium. In this work we will study if the intrinsic kinetics of hydrate dissociation affects the overall gas production and investigate if the equilibrium models are sufficient. For this purpose we employed the Kim-Bishnoi[15] kinetics model combined with the mass and energy equations to study the methane hydrate decomposition by the depressurization scheme.

Abstract In an earlier paper, it has been shown that both the GOR and the composition of produced gases in a SAGD project may be calculated from first principles by considering the solubility of gases in the produced fluids. A simulated production forecast from an Athabasca property is used to calculate the gas production characteristics for three cases; (a) original cap gas at virgin pressure: (b) cap gas replaced at the same pressure with carbon dioxide; and (c) cap gas replaced with flue gas from the steam generator. Comparison of the three cases shows that case (b) and (c) are accompanied with gas production containing significantly higher fractions of the re-pressurization gases, carbon dioxide and/or nitrogen, than case (a). The presence of the non-combustible gases introduces a thermal inefficiency if the normal practice of directing produced gases to the steam generator is followed. The effect of this inefficiency is calculated by estimating flame temperature for combustion of gas from case (a), and comparing with the other two cases. The inefficiency is then corrected by adding make-up gas to the gas from case (b) and (c), until the flame temperature is identical to that of case (a). The potential for sequestration of the greenhouse gas CO 2 is then considered in terms of initial CO 2 injected, cumulative CO 2 produced back and CO 2 formed by combustion of make-up gas. The predicted overall utility of depressurized zones for sequestration purposes is discussed. Introduction In Alberta, the Energy and Utilities Board has found that a resource conflict exists between production of bitumen and overlying gas in the McMurray formation. For the Athabasca oil sands deposit the Board has already ordered the cessation of drilling for gas reserves, and shut in existing gas production in the Surmont area. At the time of writing, further resource conflict hearings are in progress. Accordingly, there has been interest in the possibility of repressurization of depleted gas caps, such that bitumen recovery could still follow gas production. In view of recent concerns about reductions of emissions of the so-called "greenhouse gases", attention has turned to the potential for sequestration of locally available carbon dioxide or flue gases for the purpose of achieving the repressurization. In a recent paper, a predictive capability of gas production from production projects using Steam Assisted Gravity Drainage (SAGD) technology was Described 1 . The concept employed in such predictions is that produced gases from SAGD are not normally produced by free gas entering the producing wellbore, but by gases dissolved in the produced fluids. The Henry's Law constants for the important gases in water, and to a lesser extent bitumen, are known under the prevailing conditions of temperature and pressure, and are given in reference 1. If one assumes that either carbon dioxide or flue gas is injected into the gas zone after 90% depletion of the gas, and since SAGD always produces methane, carbon dioxide and smaller amounts of hydrogen sulphide, it is possible, with the aid of a bitumen production forecast from a simulator, to predict the composition and gas: oil ratio (GOR) of the produced gases and so obtain a carbon dioxide balance for such a repressurization scheme.