The correct explanation for the non-Darcy behavior (or effect) on gas flow through porous media has been debated for decades. Non-Darcy behavior (i.e. extra pressure drop) has been more logically ascribed to fluid inertia (caused when gas under high flow rate is forced through tortuous rock) than to turbulence. This high flow rate, non-Darcy concept has been adopted and extended to explain the concave upwards nature of the back-pressure plot. However, two anomalies arise:the laboratory determined values are much lower than the field observations, in other words, the field gas velocity is much less than the gas velocity used in laboratory;there are numerous experimental data showing that the rock permeability is a function of the net-stress (mainly, overburden pressure minus pore pressure) regardless of the gas flow rates. We define this permeability reduction due to net-stress decrease as the net-stress effect. During the gas production, we believe that the non-Darcy behavior should be caused by both the effect and the net-stress effect. By combining these two effects, the scale of the non-Darcy observed in fields is in the range of laboratory experimental values. This paper also shows the applications of using these two effects to analyze the back-pressure test data. Introduction While measuring gas permeability in the laboratory at atmospheric conditions, researchers have found that gas no longer follows Darcy's law in the high gas flow regime. An extra term is added to the Darcy equation to account for this non-Darcy behavior. In this paper, we refer the extra pressure drop due to high velocity as the effect. Most states in the US require a back-pressure test for all gas wells to estimate the deliverability of the wells. The results of back-pressure tests are plotted in the form of p 2 vs. Qsc. Usually, the slope of the back-pressure plot is greater than one. This means that the well exhibits non-Darcy behavior. The logical explanation is the high velocity effect experienced in the laboratory. The effect was originally mistaken as the turbulent effect. Later, it was recognized and accepted as the effect of inertia. It is almost impossible to have turbulent flow in a consolidated rock. Laboratory experimental values of k, the product of permeability and coefficient, are in the range of 104 to 106 darcy/cm. In many gas wells, even at low production and flow velocity, their corresponding back-pressure curves still give slopes greater than one. Rarely does a back-pressure curve give an unit slope. To match the field data, sometimes, the value must be increased 100 times or more. Compared to laboratory estimates, the factor may increase in high pressure environments such as in gas fields. Only one study (Warpinski et al.) shows the measurement of the factor under high pressures. The interpreted data indicates that the k values are still in the same range of the data observed under atmospheric conditions. Actually, their data shows the factor increases when the net-stress increases, however, their k values were relatively insensitive to the net-stress. It is well known that the gas permeability may reduce during drawdown. This is particularly true for naturally fractured reservoirs. The reduction of pore pressure increases net-stress. If no new fractures are induced during this stress alternation process, the increase of the net-stress may restrict the flow path, therefore, reduces the gas effective permeability. This gas permeability reduction is referred to as the net-stress effect in this paper. This net-stress effect has not been incorporated in many petroleum engineering practices including in analyzing the back-pressure data. Back-Pressure Test In many states of the US, the back-pressure test is required for a gas well and is documented by the regulatory agency. P. 191^

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The primary goal of this study was to couple reservoir characterization of the Abo Formation with hydraulic fracture analysis and subsequently, to infer infill drilling potential. Two detailed case studies were investigated to reevaluate original hydraulic fracture treatment designs, to compare and evaluate fracture parameters, and to determine if the fracture treatments were providing sufficient reservoir stimulation. Approximately 80 wells were studied in the southern part of the Pecos Slope Abo Field. Decline curve analysis was performed on all wells by a modified set of Fetkovich type curves. Analysis of this work show linear to near-linear flow in most cases with permeability values less than 0.1 md and variations in reservoir properties as is typically observed in low permeability reservoirs. These variations resulted in difficulty in evaluating infill drilling potential. Evaluation of fracture stimulation treatments was accomplished by matching recorded surface treating pressure with a fracture propagation model. Unusually high initiation pressures were observed in the case study wells; initial stress state, vertical fracture growth, fracture toughness, perforation restrictions, and the development of multiple fractures in a single, bounded layer were evaluated as possible causes for the high initiation pressures. Results from this work showed the multiple fractures model providing the best match for the two wells. Fracture length varied from approximately 1150 ft to 750 ft with a single fracture model and was reduced by approximately 10 to 30% for each additional fracture added. The fracture data was input into a fractured well performance model, which was used to match the production rate and therefore verify the process. The integration of decline curve analysis and fracture analysis provided better descriptions of reservoir properties and more accurate designs of fracture propagation models. This combined approach also improved evaluation of infill drilling potential by evaluating reservoir properties and stimulation. Background The Pecos Slope Abo Field is located in southeastern New Mexico in north central Chaves County, directly north and east of the City of Roswell (see Figure 1). The producing area of the Abo formation is located on the northwestern part of the northwest shelf of the Delaware Basin. The structure is a gently eastward-dipping homocline, which occurs over the entire producing area2. The depositional facies of the Abo were influenced by the positive and negative features of the rise of the Pedernal highlands to the west, which had a marked effect on sedimentation during the late Pennsylvanian and early Permian3. The upper lithologic unit is approximately 600 ft thick and is composed of interbedded mudstones and lenticular sandstones; deposited in a fluvial deltaic system. The gas-bearing sandstones are very fine-grained, arkosic and hematitic4. The Pecos Slope Abo Field was originally discovered in June of 1977 but development did not escalate until the early 1980's. In May of 1981 the Abo Formation was designated, as a tight gas formation. As a result of the tight gas designation, the Abo Formation became the leading target for natural gas in New Mexico in late 1981. The well spacing was restricted in the past to 320-acres but currently is 160-acres. Well spacing is reduced in order to increase the drainage area and improve recovery. Currently over 800 wells have been drilled in the Pecos Slope Field.