TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents the results of using a shale-specific, finitedifference reservoir simulation model to history match and forecast production data from the Barnett Shale reservoir. The paper will illustrate the many uses of the model for vertical and horizontal wells including determining gas in place, recovery factors, optimal well spacing, drainage areas and drainage shapes, optimal fracture half-lengths and conductivities, infill evaluations, horizontal well modeling and optimal number of stimulation treatments, analysis of microseismic data, and compression evaluations. The model was developed in the early 1990s to incorporate all of the production mechanisms inherent in shales including matrix gas porosity, gas desorption isotherm, single-or two-phase flow of gas and water in the natural fractures, layers, complex hydraulic fractures, and variable flowing bottomhole pressures. The paper will discuss the methodology to incorporate all field data into the simulator including core, logs, well test, completion, stimulation, microseismic, and production data. Examples will be given using public datasets. We also show production comparisons between vertical and horizontal wells since this is of topical interest in the play's development history. Furthermore, we discuss the various types of data to collect, their importance to proper stimulation design, and the integration methodology to evaluate and complete shale reservoirs.
An algorithm has been developed for computing the pressure response for a well with constant wellbore storage and non-Darcy skin factor across the completion. The algorithm has been used to generate type curves for drawdown and buildup tests. The builduppressure-derivative response for a well with non-Darcy flow across the completion exhibits a much steeper slope during the transition out of wellbore storage than that of a well with constant skin.No reservoir model with constant wellbore storage and skin can reproduce this steep derivative. Thus, if it is present in a buildup test, the well is experiencing either decreasing wellbore storage or decreasing skin factor, or both.With the new type curves, under favorable conditions, both Darcy and non-Darcy skin components may be estimated from a single buildup test following constant-rate production. The new algorithm also may be used to model a test sequence comprising multiple flow and buildup periods. IntroductionNodal production-system analysis 1 is one of the primary tools for optimizing production and predicting well performance. In nodal analysis, reservoir performance is described through the inflowperformance-relationship (IPR) curve. To construct accurate IPR curves for gas wells, both Darcy and non-Darcy skin components must be known.The non-Darcy skin is traditionally estimated by performing a multirate test. The effective skin factor is then graphed as a function of flow rate, allowing the Darcy and non-Darcy components to be determined from a straight-line fit through the data.When multirate tests are not available, the non-Darcy flow coefficient may be estimated from correlations. However, the resulting values may be in error by as much as 100%. 2 The behavior of a pressure-transient test with infinite-acting radial flow with constant wellbore storage and skin factor is well known. 3,4 Other authors have considered the case of variable wellbore storage with constant skin factor. 5,6 This paper examines the behavior of a well with constant wellbore storage and rate-dependent skin factor for drawdown and buildup tests. Buildup tests with non-Darcy skin factor exhibit a much steeper pressure derivative during the transition out of wellbore storage than those with Darcy skin factor, as seen in Fig 1. The new type curves provide three significant contributions to the industry: (1) they allow the test analyst to recognize non-Darcy flow from a log-log diagnostic plot of pressure change and pressure derivative; (2) they provide estimates of both Darcy and non-Darcy components of skin factor from a single buildup test, allowing construction of IPR curves based on well performance instead of correlations; and (3) they help identify the cause of high skin factors.High-rate wells with high skin factors represent excellent candidates for stimulation. 7,8 However, because of the risks involved in any workover, there often is a reluctance to stimulate such a well. Given that high-rate wells are the ones most likely to exhibit non-Darcy skin, the new type curves will...
This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
The Antrim Shale of the Michigan Basin has been an active gas play with over 3,500 wells drilled over the last 5 years. There is substantial evidence that the Antrim must be fracture stimulated to be economical and that two~stage treatments provide the best results. However, due to the shallow depths (500-2300 ft) and naturally fractured nature of the Antrim, fracture geometry is complex, and determination of optimal fracture treatments is not straight forward. Because historical field comparisons did not provide insight on the optimal fracture treatments, the Oas Research Institute (OR!) instituted a field~based project for the specific purpose of evaluating the geometry of hydraulic fractures in the Antrim.Open-and cased-hole tests were performed on two separate Antrim wells -a shallow producer (600 +/ft) and a deep producer (1550 +\-ft). Open-hole testing and data collection consisted of in-situ stress and mechanical property testing with Halliburton's THETM Tool (9 tests) and a detailed suite of geophysical logs including dipole sonic logs and natural fracture detection logs. Cased-hole testing consisted of preã nd post-fracture injection/falloff tests, minifracture treatments, multiple isotope tracer and tracer logs, and treating pressure and production data analysis.Analysis of open-and cased-hole data from the shallow and deep wells suggests that subvertical fractures are being created and are probably following existing natural fracture planes. The shallow depths, low in-situ stresses, and extremely fractured nature of the Antrim probably results in 343 the preferential opening of eXisting fractures instead of the creation of new fracture planes. As a result, the creation of multiple fractures and severe near wellbore tortuosity is likely. Therefore, the natural fractures are responsible for increased leakoff and will greatly impact created fracture geometry. The results also suggest that creating long propped hydraulic fractures in the Antrim is not likely due to the creation of mUltiple fractures.
This paper presents the results of a comprehensive reservoir evaluation of the New Albany shale reservoir in northern Kentucky and southern Indiana and Illinois. Although initially compared with the Antrim shale in the Michigan basin, the New Albany shale has been found to have very different production characteristics than the Antrim. This paper presents the results of a comprehensive study performed on behalf of the New Albany Shale Producibility Consortium (NASPC). The objectives of this study were to determine the controls on production characteristics of wells in the New Albany shale, understand well reserves, and ascertain the potential for future development in the play. The reservoir evaluation included all available geologic, formation evaluation, production, and reservoir data from multiple fields within the play. During this study, core testing was conducted to develop baseline properties required for reservoir evaluation. Study results indicated that fracture characteristics within the play are the key driver for well production characteristics and reserves. In addition, we found that matrix gas porosity, bulk permeability, methane adsorption characteristics, and net pay thickness also differentiate the New Albany shale reservoir from the Antrim. The results also indicated that horizontal wells may have the potential to improve productivity and reserves within the play by specifically targeting the characteristics of the fracture pattern within the reservoir. The results of this paper may be useful to producers in fractured shale plays who wish to improve their understanding of flow characteristics and well performance. The work presented in this paper is important because it increases the knowledge base of shale reservoir properties and characteristics and because it describes an approach that can be used to characterize shale reservoirs. Background The New Albany shale is an organic-rich shale located over a large area in southern Indiana and Illinois and in northern Kentucky (see Fig. 1). On average, the shale appears at 500 to 2,000 ft depth.1,2 A representative well log from a producing well in the play is shown in Fig. 2. The gross thickness of the organic New Albany shale ranges from about 100 to 150 ft. The shale is generally broken into four stratigraphic intervals as labeled in Fig. 2. These are the Clegg Creek, Camp Run/Morgan Trail, Selmier, and Blocher intervals from top to bottom. New Albany shale is known to be a productive gas reservoir, with some wells producing for many years. By the mid 1990s, there were 200 to 300 producing wells targeting the shale interval. There were several large, multiwell producing fields within the basin. Most of these fields were developed utilizing vertical wells, and fracture treatments were used to access and stimulate the New Albany shale interval. Gas production from wells drilled in the New Albany shale was found to be generally less than operators expected based on experiences in developing producing wells in the Antrim shale in northern Michigan. Production in the New Albany shale ranged, generally, from 30 to 100 Mscf/D per well. Water production from wells in the play has proved to be highly variable, with some wells making very little water and other wells making more than 1,000 B/D of water. Much of the mid 1990's interest in the New Albany shale was generated by operators wishing to transfer expertise gained in the Antrim shale to the New Albany shale. Projects consisted both of expansion of existing fields within the play and exploration projects in new development areas. At that time, however, there were no comprehensive reservoir studies done on the New Albany shale. Operators generally assumed that the characteristics of the shale would be similar to those of the Antrim.
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