The simulation of the performance of a horizontal well has generated certain new and important challenges. These include the partial penetration of the well in the horizontal direction within the allocated drainage area, the positioning of the well between the vertical boundaries, the distance from the parallel horizontal boundaries, and the permeability anisotropy. In addition, there are special problems in the simulation of the response of fractures (natural and induced) in regard to their contact with the well (longitudinal or transverse), their conductivity, and the conductivity distribution along the fracture.We developed new numerical techniques to facilitate the simulation of these diverse problems. We use a locally refined perpendicular bisection grid to describe the horizontal (or deviated) wellbore. The grid is strictly orthogonal for the anisotropic case, and wellbore blocks are almost regular octagonal prisms. The transition to the coarse Cartesian grid is also orthogonal. The fully implicit formulation ensures the stability of the numerical solution. Our results are found to be in excellent agreement with published analytical or semianalytical approximations. In addition, the results offer flexibility that is not possible with analytical solutions. The grid system used is particularly amenable to handling practical problems with real reservoir geometries and configurations.This paper presents a comprehensive numerical simulation of problems associated with horizontal wells, including the arbitrary positioning of the well within a fully anisotropic medium. Hydraulic or natural fractures that intersect the well in the longitudinal or transverse direction are simulated for both infinite and finite conductivities.

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TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractProducing natural gas from shale gas reservoirs has gained momentum over the past few years in North America and will become an increasingly important component of the world's energy supply. A shale gas reservoir is characterized as an organic-rich deposition with extremely low matrix permeability and clusters of mineral-filled "natural" fractures. Shale gas storage capacity is defined by the adsorbed gas on the organic material within the shale matrix and free gas in the limited pore space of the shale rocks. Horizontal drilling and hydraulic fracturing are the primary enabling technologies to obtain economical production from the shale gas reservoir. This paper presents a comprehensive reservoir simulation model to study the impact of reservoir and hydraulic fracturing parameters on production performance of a shale gas reservoir. The simulation model was constructed as a multi porosity system with matrix sub-grids to account for transient gas flow from the matrix to the fracture. The extended Langmuir isotherm was used to model the desorption process of multiple components during the production. Primary hydraulic fractures perpendicular to the horizontal wellbore were modeled explicitly with thin grid cells that preserved the finite conductivity. The hydraulically-induced fracture network around the horizontal well was characterized by the matrix-fracture coupling factor (sigma) and permeability of the fractures.The study was aimed to quantify the influence of the reservoir and hydraulic fracture parameters using experimental design, including porosity and permeability of the reservoir matrix and fracture, matrix-fracture sigma factor, matrix subdivisions and, primary hydraulic fracture half-length, height, spacing and conductivity, rock compaction, non-Darcy flow coefficient, as well as gas content. Sensitivity tests were performed to identify the most influential reservoir and hydraulic fracture parameters and provided important insights into the impact of uncertainties on shale gas production forecasts, which can be critical for fracture treatment design and production scheme optimization.

SPE Members Abstract The term "windowing technique" means time- dependent replacement of grids and parameters during a simulation run. The window is a confined area within the block model and it contains an other grid than the surrounding basic grid. The basic grid is Cartesian, while the grids inside windows can be Cartesian but with a different spacing, or 2D or 3D irregular grids. A window may also contain a different parameterization of the same basic grid. The basic Cartesian block model and the windows are independent entities. A well-defined relation between windows and basic grid permits the exchange of the grids during the run. Dual timestepping allows the use of large global timesteps outside windows and other (usually smaller) timesteps inside windows. Effective parallel processing of the windows is also possible. Potential applications of windows are well test simulation models embedded in coarse grids, modeling of arbitrary-direction horizontal wells, different realizations of stochastic modeling, effective parameter updating during the life of a model, etc. Introduction "Grid construction is a tedious and time-consuming task". This statement was made by many authors, including ourselves. Albeit the situation has changed over the years and many improvements have been presented for certain problems, most of the developments were stand-alone pieces of work and the results were difficult to apply in every-day work. While simulation grids for practical examples are static, simulation scenarios and physical processes change during the simulation run and during the life of the model. The initially set up block model becomes inappropriate for the new situations. Using static grids, the whole model has to be regridded, reparameterized and eventually rematched to honor the new situation. Among the cases which might necessitate a new grid are: the introduction of horizontal wells not parallel to grid lines, fine radial grids for well test simulation, (local) tensorial permeability anisotropy, secondary grid refinement when EOR-processes are simulated in the prediction runs (secondary grid refinement means that the refinement is introduced during the simulation run and is not present at the beginning), or irregular grids for honoring stochastic reservoir data. P. 105

Summary Methane production from coalbeds, while originally a safety measure, hasemerged as a major source of gas for a number of locations worldwide. Gasdesorption is the main production mechanism. This is accomplished currently bythe production mechanism. This is accomplished currently by the hydraulicfracturing of vertical wells; draining of water, which is always present in thelimited pore structure; and reducing pressure to begin the desorption process. However, hydraulic fractures tend to propagate parallel to the main naturalfissures and thus normal to the smallest permeability. This is the leastfavorable position. Simulation shows that horizontal wells drilled in theorthogonal direction (i.e., normal to the maximum permeability and the mainnatural fissures) can provide significantly larger gas rates. Several smallhydraulic fractures, performed in the horizontal well with proper zonalisolation, can augment production further. Considering the highly fissured, cleated nature of coalbeds, small stimulations, with much more modestexpectations, are far easier to perform than the single treatments required ina vertical well. Design criteria, well sizing, and stimulation treatment numberand magnitude are calculated and presented. Introduction The coalbed methane industry has emerged as a significant source of naturalgas production. The original perception of coal-associated methane as a hazardin mining operations is becoming obsolete. Today, a coalbed is considered areservoir from which large quantities of methane can be extracted. In the U.S. alone, the total coalbed resource is estimated to be 4 × 10-13SCf [1 × 10-13 std m3], of which 9 X 10-13 SCf [2.5 × 10-12 std m3] isconsidered recoverable reserves. Several potential mechanisms have been identified during the production ofcoalbed methane, including free gas from associated production of coalbedmethane, including free gas from associated natural fractures and gasdesorption from the coal surface as the reservoir pressure declines. Primaryporosity in coals is very small, rarely exceeding 0.05, with typical valuesaround 0.02. Reservoir thickness is also very small (this is the thickness of acoal layer) and is frequently less than 10 ft [3.3 m]. Vertical wells, allowing exceedingly small contact between them and a coalseam, are rarely, if ever, acceptable producers. Production rates do not exceeda few thousand cubic feet a day, and Production rates do not exceed a fewthousand cubic feet a day, and they are hindered further by relativepermeability problems caused by the presence of associated water. Hydraulic fracturing of vertical wells in coalbeds has been attempted in anumber of cases. The perception of coal seams as fracturable reservoirsprompted the study of their rock and reservoir properties as they might affectfracture design. Several features distinguish coalbeds from other reservoirs. In addition tothe small thickness and porosity already mentioned, the (also small)permeability is usually highly anisotropic, with the maximum permeabilityinvariably along the maximum horizontal stress. This would make the hydraulicfracture parallel to the maximum permeability, which is, of course, highlyundesirable during production when the bilinear flow concept would necessitatea large permeability normal to the fracture face. Permeability anisotropy in coalbeds is caused by natural fissures Permeability anisotropy in coalbeds is caused by natural fissures that, although anisotropically distributed, are also at various angles along thehydraulic fracture path. These fissures may open during the treatment, providing large fluid leakoff paths, readily dehydrating the slurry, andresulting in screenouts. To combat this, fracture designs have used very smallproppant slurry concentrations (frequently 2 lbm/gal [240 kg/m3), leading tovery lackluster production rates. Also, fines migrating from the coal fissuresystem may penetrate the hydraulic fracture and reduce its conductivityfurther. Of the primary fracture treatment variables, the Young's modulus of coalbedsis very small (between 1 × 10-5 and 1 X 10-6 psi 16.9 × 10-8 to 6.9 × 10-9 Pa])compared with normal fracturing candidates with Young's moduli between 3 × 10-6and 10-7 psi [2 × 10-10 and 6.9 × 10-10 Pa]. In the best cases, this featurewould result in short, wide fractures instead of the long penetrations requiredby such low-permeability reservoirs. Finally, coalbeds to be fractured, presumed to be single reservoirs, presenta large variation in the success of the treatment because of stress variations. They are usually multilayered and are prone to T-shaped fractures. Thesefeatures and others, along with guidelines for adjusting fracture design modelsand recommendations for fracturing treatments, are presented later. Obviously, maximization of the gas production rate from coalbeds is theissue at hand. From all the above, it should not be too surprising thatproduction from unstimulated or hydraulically fractured vertical wells isusually small, ranging from 50 to 230 Mscf/D [1.4 × 10-3 to 6.5 × 10-3 stdm3/d] in 30 wells in an Alabama field 13 and a cumulative 6 to 7 MMscf/D [1.7 × 10-5 to 2 × 10-5 std m3/d] from another 31-well development. A no-proppant foamstimulation in a well was reported to result in an average 4.5-month productionof 49 Mscf/D [1.4 × 10-3 Std m3/d]. production of 49 Mscf/D [1.4 × 10-3 Stdm3/d].