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Collaborating Authors
Results
Comparison of Computation Methods for CBM Performance
Mora, C.A. (Texas A&M University) | Wattenbarger, R.A. (Texas A&M University)
Abstract Coalbed methane (CBM) production is somewhat complicated and has led to numerous methods of approximating production performance. Many CBM reservoirs go through a dewatering period before significant gas production occurs. The production process, with dewatering, adsorption of gas in the matrix and molecular diffusion within the matrix, can be difficult to model. Several authors have presented different approaches involving the complex features related to adsorption and diffusion to describe the production performance for coalbed methane wells. Various programs are now commercially available to model production performance for CBM wells, including reservoir simulation, semi-analytic and empirical approaches. Programs differ in their input data, description of the physical problem and calculation techniques. This paper presents comparative results of several available programs using different test cases (vertical fractured wells and horizontal wells). Introduction The flow mechanics of coalbed methane (CBM) production have some similarities to the dual porosity system. Figure 1 compares the actual reservoir and its idealization model where the matrix and the cleat systems can be differentiated. Also, three sets of normal parallel fractures are shown (face cleats, butt cleats and bedding plane fractures). CBM models are characterized as a coal/cleat system of equations. Most of the gas is stored in the coal blocks. Gas storage is dominated by adsorption according with Equation (1). Equation 1 (available in full paper) Adsorbed gas content, Gc, is calculated with the Langmuir equation, as follows: Equation 2 (available in full paper) Gas desorbs in the coal block and then drains to the fracture system by molecular diffusion (Fick's law rather than Darcy's law). The drainage rate (Fick's law) from the coal block can be expressed using Equation (3): Equation 3 (available in full paper) For Equation (3), q* represents drainage rate per volume of reservoir. For CBM reservoir modelling, sorption time is related to the transfer shape factor, s, and the diffusivity term, Dc. Sorption time, t, expresses the diffusion process by means of Equation (4): Equation 4 (available in full paper) By definition, t is the time at which 63.2% of the ultimate drainage occurs when maintained at constant surrounding pressure and temperature. The typical production profile for a CBM well is shown in Figure 2. The production behaviour exhibits only water production from the cleat system at the beginning (flow through the cleat system is governed by Darcy's law). Then, due to the reduction in formation pressure, gas starts to desorb from the matrix creating a concentration gradient, and gas and water flow through the cleat system. The water rate decreases and the gas rate increases until the gas peak is reached (the gas production behaviour in this stage is dominated by diffusion). Finally, when depletion in the reservoir is significant, the gas rate declines. Several authors have presented different approaches to describe the production performance for coalbed methane wells. Zuber et al. pointed out that history matching analysis can be used to determine CBM reservoir flow parameters and predict performance by using a simulator modified to include storage and flow mechanisms.
- North America > United States (0.69)
- North America > Canada > Alberta (0.15)
Abstract A naturally fractured reservoir is characterized as a system of matrix blocks with each matrix block surrounded by fractures. The fluid drains from the matrix block into the fracture system which is interconnected and leads to the well. Warren and Root introduced a mathematical model for this dual porosity matrix-fracture behaviour. Their model has been widely used for many types of reservoirs, including tight gas and coalbed methane reservoirs. A key part of their model is a geometrical parameter (shape factor) which controls the drainage rate from the matrix to the fractures. Although Warren and Root gave formulas for calculating shape factors, many other authors have presented alternate formulas, leading to considerable confusion. In addition to the size and shape of a matrix element, two cases are considered by the authors: constant drainage rate from a matrix block and constant pressure in the adjacent fractures. The current work confirmed the correct formulas for shape factors by using numerical simulation for the various cases. It was found that some of the most popular formulas do not seem to be correct. A summary of the correct shape factor formulas is presented. Introduction Naturally fractured reservoirs can be characterized as a system of fractures in very low conductivity rock. The mathematical formulation of this 'dual porosity' or 'double porosity' system of matrix blocks and fractures was presented by Barenblatt et al. The first system is a fracture system with low storage capacity and high fluid transmissibility and the second system is the matrix system with high storage capacity and low fluid transmissibility. The matrix rock stores almost all of the fluid, but has such low conductivity, that fluid just drains from the matrix 'block' into adjacent fractures, as is shown in Figure 1. The fractures have relatively high conductivity, but very little storage. The drainage from the matrix to the fractures for dual porosity reservoirs was idealized by Warren and Root according to Equation (1). Equation 1 (available in full paper) Equation (1) is in the form of pseudosteady-state flow which means that early transient effects have been ignored. Pseudosteady-state also means that the drainage rate is constant. The units of Equation (1) are volume rate of fluid drainage per volume of reservoir. The units of the shape factor, s, are 1/L. For dual porosity reservoirs, when pressure test analyses are available, the product s - km can be determined using Equation (2), but cannot be separated. Equation 2 (available in full paper) The inter porosity flow coefficient, ?, determines the interrelation between matrix blocks and the fracture system. When km is available from core or log analysis, then shape factor, s, can be estimated. For cases where pressure test analyses are not available, formulas can be used to estimate shape factor. However, there are conflicting equations and values for s in the literature. Many authors have interpreted Equation (1) to be the equivalent long-term reservoir drainage equation with pf held constant and drainage rate changing with time.
- Europe > United Kingdom (0.28)
- North America > United States > Texas (0.15)
Abstract It is common for field models of tight gas reservoirs to include several wells with hydraulic fractures. These hydraulic fractures can be very long, extending for more than a thousand feet. A hydraulic fracture width is usually no more than about 0.02 ft. The combination of the above factors leads to the conclusion that there is a need to model hydraulic fractures in coarse grid blocks for these field models since it may be impractical to simulate these models using fine grids. In this paper, a method was developed to simulate a reservoir model with a single hydraulic fracture that passes through several coarse gridblocks. This method was tested and a numerical error was quantified that occurs at early time due to the use of coarse grid blocks. Introduction A single hydraulic fracture is conventionally modelled for research purposes using fine grids. In actual field models of tight gas reservoirs, there are several wells with hydraulic fractures (see Figure 1). These hydraulic fractures are usually very long. They can extend in length to more than a thousand feet. These long hydraulic fractures extend for several gridblocks in a simulation model (Figure 1). Therefore, it is very difficult to use fine grids to simulate these actual field models. Some authors suggested the replacement of the hydraulic fracture by an effective wellbore radius, but this technique is only valid when the hydraulic fracture does not extend beyond the boundaries of one gridblock. There were also attempts by another group of authors to modify transmissibility multipliers of the gridblocks, which contain hydraulic fractures. However, these attempts were done for hydraulically fractured horizontal wells. In addition, these attempts were based on empirical rules that had no basic theory behind them. In this paper, the means to model hydraulic fractures in coarse gridblocks are demonstrated. Pseudo-permeability values were used to account for the hydraulic fracture passing through the coarse gridblock. Several simulated cases were shown in this paper and compared to rigorous analytical solutions to prove the validity of the method proposed. An alternative way to model hydraulic fractures in coarse gridblocks (also based on theory), developed by Elahmady but not discussed in this paper, was to modify the transmissibility multipliers of the gridblocks that contain the hydraulic fracture. Elahmady cautioned that there are different ways to use transmissibility multipliers depending on the kind of simulator that is used. The authors would like to note that during the course of their study they were aware of the work by Peaceman where the calculated pressures in gridblocks containing wells, pwb must be corrected to formation face pressure, pwf. Peaceman's equation is programmed into any conventional reservoir simulator for the case of radial flow. Elahmady repeated Peaceman's numerical experiments, but for linear flow (which is the focus of this paper) instead of radial flow, and reached a conclusion that pwf = pwb for the case of linear flow.
Abstract Many tight gas wells (permeability less than 0.1 mD) exhibit transient linear flow; sometimes for several years. This behaviour differs from radial flow in many ways. This paper reports another import difference between linear flow and radial flow? rate sensitivity. It has been shown and accepted for years that real gas pseudopressure can be used to apply analytical solutions to transient radial flow. However, it has been noticed that analytical solutions can be in serious error when applied to transient linear flow. Specifically, the slope of the โt plot departs from the analytical value as the flow rates or degree of drawdown becomes higher. This paper demonstrates the rate/drawdown sensitivity of transient linear flow. Then a correction factor is presented which corrects the slope of the plot and improves the accuracy of โk Ac and OGIP, as calculated from production/pressure performance. Introduction Many wells in tight gas reservoirs have long-term performance which exhibit only linear flow, not radial flow, during the transient period. Wells have been observed which stay in the transient linear flow regime for several years. Some of these wells have hydraulic fractures and some do not. It is usually not practical to analyze tight gas wells with build-up tests, but long-term production and pressure data can be used for analysis. Previous papers have presented methods of analysis. The analysis of these wells comes from plotting [m(pi) - m(pwf)]/ Qg vs. โt and observing the slope, mCPL, and the end of the straight line, tesr (end of the transient linear flow period). From these values, โk Ac and OGIP can be calculated. It has long been accepted that radial flow transient solutions can be approximated by analytical solutions, in terms of m(p), regardless of flow rate. Constant rate solutions have been emphasized, but it can also be shown that constant pwf flow can also be approximated by analytical solutions, regardless of the level of drawdown The drawdown/rate dependency linear flow is different than analysis of radial flow. This difference was demonstrated with reservoir simulation in this work. A correction method was developed to improve the accuracy of analysis of transient linear flow for analyzing tight gas wells. Effect of Drawdown on Transient Linear Flow (Constant pwf) A number of transient linear flow cases were run with constant Pwf. It was found that these cases did not have the same slopes as the analytical solution, but varied according to the level of drawdown. In order to demonstrate this effect, a dimensionless drawdown parameter is defined as follows: Equation (Available In Full Paper) Some results are plotted in Figure 1. It can be seen that the slope of these plots is greatly affected by the level of drawdown, DD. As the drawdown value increases, the slope (mCPL) value decreases. Since the analysis equations are based on analytical solutions, the calculations may be wrong when actual data is analyzed.
- North America > United States (0.96)
- North America > Canada > Alberta (0.30)
A Strategic Gas Field Development Case in Sandstones Using Seismic Amplitudes and Dynamic Characterization
Arevalo-Villagran, J.A. (Unam-Pemex E&P) | Cinco-Ley, H. (PEMEX E&P) | Gutierrez-Acosta, T. (PEMEX E&P) | Martinez-Romero, N. (UNAM-PEMEX E&P) | Garcia-Hernandez, F. (PEMEX E&P) | Wattenbarger, R.A. (Texas A&M University)
Abstract The objective of this paper is to present a process for improving the planning of gas field development. We discuss how static and dynamic characterization can be combined to help optimize gas field development. The main concepts, methodologies, and results are shown for an actual Mexican gas field. Static characterization centred on a series of seismic amplitude maps constructed from 3D seismic interpretation. Dynamic data included production data and initial pressure gradients which were useful in delineating individual reservoirs and establishing hydraulic communications between certain reservoirs. The seismic amplitude maps, modified by considering the dynamic data, improved the evaluation of reservoir quality, the estimation of drainage areas, original gas-in-place, and proved reserves. A strategy for the optimal field development was designed by using this combination of seismic amplitude maps modified with information from logs, cores, production, and pressure data. Introduction The subject gas field is located in the central area of the Veracruz basin southeast of Veracruz, Mexico. The field was discovered in 1921 with Well 1, which was drilled by a foreign company. The field is formed by many lenticular sandstones containing gas at abnormal pressures. The first producer well (Well 3) was completed in 1962 in Tertiary sandstones. The field has had a total of 24 wells drilled, in addition to Well 1. Fourteen wells are now gas producers (Wells 3, 4, 5, 6, 201, 402, 403, 404, 405, 406, 412, 415, 420, and 436), nine wells have watered out (Wells 10, 12, 13, 15, 101, 407, 414, 428, and Ma-1), and one well was lost because of mechanical failure (Well 102). Currently, the gas field is comprised of three main producing sandstones: the sandstones at the base of the Lower Pliocene (body "E" located at 1,600 - 1,680 m or 5,249โ5,512 feet of depth) which began development in November 1969 with Well 5; the sandstones of the Upper Miocene (body "G" located at 2,050 - 2,250 m or 6,726 - 7,382 feet of depth) which began development in August 1966 with Wells 3, 4, and 6; and, the sandstones of the Late Medium Miocene (body "M" located at 2,500 - 2,700 m or 8,202 - 8,858 feet of depth) which began development in August 1988 with Well 201. Table 1 shows the well names, the reservoir, and fluid data for each producing sandstone. In 1999, a series of 3D seismic surveys were performed covering an area of 240 km2 (59,305 acres). The interpretation of the 3D seismic surveys allowed the construction of several seismic amplitude maps. These maps were used for detecting significant volumes of gas related to high seismic amplitude areas, while establishing geological models and delimiting stratigraphic features. The seismic amplitude maps were calibrated with reservoir and fluid properties as well as production data obtained through productive wells from different sandstones. Using these modified maps then led to an improved development plan for the field. The fundamental objective of this work is to present the methodology and results of the teamwork aspect of this integrated reservoir management study.
- Phanerozoic > Cenozoic > Neogene > Miocene (0.74)
- Phanerozoic > Cenozoic > Neogene > Pliocene (0.54)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- North America > Mexico > Veracruz > Veracruz Basin (0.99)
- North America > Mexico > Gulf of Mexico > Veracruz Basin (0.99)
Abstract Many tight gas wells show transient linear flow that lasts for many years. Linear flow is normally associated with hydraulic fractures, but tight gas reservoirs may contain geometrical effects that lead to linear flow behaviour. In this study, long-term linear flow caused by the presence of natural parallel fractures is investigated and a systematic procedure to analyze linear flow in tight gas wells is described. Application of this methodology to production analysis of three tight gas wells, and validation of the results by using numerical simulation, is described. Introduction Linear flow is characterized by t behaviour during transient flow. This is sometimes associated with hydraulically fractured wells with linear flow perpendicular to the fracture. At the end of linear flow, the pressure response (for a constant rate solution) of these wells flatten as flow enters from outside the fracture tips. However, this paper refers to observed well behaviour in which the pressure response becomes steeper at the end of linear flow, indicating an outer boundary effect. For these wells, there appears to be only linear flow during transient and outer boundary dominated flow. Actual field data shows long-term linear flow for years in a large number of wells because of the extremely low permeability. A "half slope" (slope = 0.5) on a log-log plot of [m(pi) [m(pwf)]/ Qg vs. t for either constant gas rate production, qg, or constant bottomhole flowing pressure, Pwf, indicates linear flow. Long-term linear behaviour has been reported in tight gas wells which have no or not particularly large fracture treatments. The reason for linear flow may not be known for a particular well. But several papers discuss physical scenarios which may cause linear flow, including the occurrence of natural fractures. Tectonic stresses determine the direction of natural fractures. These natural fractures may tend to be parallel to the hydraulic fracture plane and cause linear flow even if the hydraulic fracture length was limited. However, if the tectonic stresses have changed since the formation of the natural fracturing, the hydraulic fracture could have a different orientation from the natural fractures. In this paper, we discuss how parallel natural fractures lead to permeability anisotropy and cause long-term linear flow. We show several field examples and outline a stepwise procedure for analyzing wells with long-term linear flow. Linear Flow Due to Anisotropy Parallel Natural Fracturing Long-term linear flow in tight gas wells may develop because of large permeability anisotropy ratios. Anisotropic permeability in porous medium has been examined in several papers and books. One of the most important reasons for anisotropic permeability is parallel natural fracturing. Figure 1 shows a sketch of a well in a closed square with a parallel natural fracture system. In order to calculate the effect of the natural fractures on permeability, we assume that the natural fractures are continuous in the x direction and there is a regular spacing between fractures, dA, in the y direction.
- North America > Mexico (0.69)
- North America > United States > Texas (0.68)
- South America > Colombia > T Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Texas > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- 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 > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract A straight-line plot of p/z vs. Gp (cumulative gas production) is widely used to estimate the original gas in place. It is known as the p/z plot technique. The linearity of that plot has been historically known to be a unique feature of a volumetric (closed) reservoir. In this paper, we show that a uniqueness problem may exist when using the p/z plot. In other words, if the reservoir is in contact with an aquifer, a straight-line may exist on that plot causing a major overestimation of original gas in place. This uniqueness problem is proved to be due solely to the unsteady state nature of aquifers. A simulation study was performed to determine the conditions for such a misleading straight line. Several examples demonstrate that it is possible to construct a synthetic data set for a water-drive gas reservoir such that a misleading straight-line plot is obtained. This misleading straight-line is shown to be due to certain rate schedules. The conventional material balance equation is coupled with an aquifer mathematical model to obtain this schedule. In this paper, an actual field case is presented as an example of this possible overestimation of original gas in place due to a misleading linear p/z plot. Introduction The material balance equation is an expression of the law of the conservation of mass, which is commonly used in reservoir engineering. For reservoirs with no water influx and no water encroachment and if we neglect formation and water compressibilities, it will have the following form which can be written also as Equation (2) Available In Full Paper. If we include all of the forces that we previously neglected, then we will have the following equation Equation (4) Available In Full Paper. If we neglect the influence of the formation and water compressibility then the Ramagost factor RM will be equal to 1, and therefore Equation (4) will be reduced to the following
Abstract An oil well can be stimulated by applying AC current to the formation in a single well. This type of stimulation can be called electrical resistance heating (ERH). The viscosity reduction which results from a higher temperature around the wellbore increases the oil production rate. This process has been tested in the field and the performance successfully matched with reservoir simulation. This study was performed to find a simple method of estimating steady state stimulated production rate. A two-dimensional simulator was developed and run for 52 cases which covered a variety of reservoir conditions. This sensitivity analysis showed that four parameters accounted for most of the variation in production rate. The parameters were initial oil viscosity, formation thickness, drainage radius and induced temperature change. The predictive equation takes the form of steady-state radial Darcy's Law with a modified oil viscosity term. The modified oil viscosity is a weighted average between the initial oil viscosity and the minimum oil viscosity at the wellbore. The weighting factor was matched to the reservoir simulation results by regression analysis. The use of this simple predictive equation agrees well with simulation results for steady state flow. Introduction Oil production can be stimulated by applying electrical power in the formation. The electrical power causes a temperature increase which reduces oil viscosity and results in increased oil production rates. Electrical energy is converted to heat in the formation by a combination of electrical resistance heating (ERR) and electromagnetic power absorption, depending on the electromagnetic power frequency. This study was- confirmed to electrical resistance heating (ERH), which is the major source of heating when low frequency (60 Hertz) AC electric power is used. The literature reveals several papers dealing with the possibility of using the ERR process for stimulating oil recovery.. Pilot studies have also been initiated in Canada, United States, Mexico, and other countries with varying degrees of Success. One of the earliest examples of electrically stimulating oil recovery was reported by World Oil in 1970. The method was designated as the "Electrothermic Heating Process". The process used an AC current applied around the wellbore. The heat was reported to improve production of low API gravity oils up to 300%. Single-phase AC electric power was used to avoid metal corrosion associated with DC electric power. Flock and Tharin mentioned multi-well ERH as a possible recovery method. They proposed using electrically heated water in secondary recovery projects to increase displacement efficiency. They also pointed out poor efficiency in electric power generation was a major drawback to the ERH method. As a result, Flock and Tharin considered ERR as a preheat for more conventional thermal processes rather than an independent recovery process. Schumacher reported on ERR using multi-well installations. Because of the high cost of electrical power it was primarily considered as a means of preheating a reservoir as noted in the Flock and Tharin paper. The problem of water flashing to steam near the wellbore was also noted.
- North America > United States (0.36)
- North America > Canada > Alberta (0.16)