In a large field with thousands of wells of different ages and qualities, determining the optimum operating pressure is a challenging task. This study looks at the Lobo Field in South Texas which has approximately 1800 tight gas wells currently in production to determine the effect of pressures on recovery and the benefits vs. costs of compression. Wells were divided into 3 groups that share similar characteristics and modeled using the integrated production modeling tools to evaluate recovery vs. line pressure. Results show that the better wells can produce longer in a high pressure system before loading up and needing lower pressure, therefore, cost of compression per unit volume is lower. Wells with lower reserves do not stay in the intermediate pressure gathering system long before needing low pressure, thus for these wells the fuel savings from having an intermediate pressure system does not offset the cost. Well head compression is only attractive for the better wells. 1. Introduction ConocoPhillips currently produces roughly 1800 wells in the Lobo Field and maintains an active drilling program adding 40–50 wells per year. Initial field development began in the late 1970's. As the field matures, reservoir pressure declines, and as a result, so does production. Optimizing production requires optimizing surface pressures. The continuous drilling program, while adding to potential recovery, exacerbates the optimization challenge because the mixture of older and newer wells has a large range of pressure needs. The long lead time of compression projects combined with the flow and load-up characteristics of numerous wells can result in significant range of uncertainty for design volumes. Timing, location, horsepower, capacity, throughput and compressor configuration are some of the numerous variables that need to be determined with constantly changing needs. Addressing questions on this issue presented a unique opportunity for a multifunctional team of reservoir, production, facility and operation disciplines to work out a compression strategy. It was necessary for the team to work together to align goals and production philosophy and to manage a balance between top priority projects in the short term and longer term projects. A strategy that balances the cost and benefits of compression for the different types of wells was developed. This paper only focuses on the methodology used to determine the benefits and estimated cost of reduction in wellhead pressure, including timing of compression. Other compressor related issues such as cost/benefit of acquisition method, installation design, maintenance philosophy, instrumentation level and fuel usage optimization, which are all part of the overall cost of compression were included in the strategy, but will not be discussed here. Compression project economics are driven by acquisition costs, installation costs, operating expenses and the production profile resulting from lower system pressure that compression provided. How will the wells respond to lower pressure? What is the lowest pressure that added rate and recovery can justify the cost of compression? First, the wells' responses must be modeled. It is very time-consuming to model all 1800 wells at the same time thus a short-cut methodology is preferred. It was determined that despite the age differences, Lobo wells share many similar characteristics and the wells can be divided in three groups. Group 1 has an average estimated ultimate recovery (EUR) of approximately 1 bcf. Group 2 has an average EUR in the 3 bcf range and Group 3 has an average EUR exceeding 6 bcf. It is sufficient to model one well from each group and use their responses to determine representative compression economics.

This manuscript will outline the stimulation design criteria for wells in the Lobo Trend in south Texas and fracture design changes based on post fracture production analysis using commercial software. Production data will be modeled with the corresponding fracture geometry. Model results will be used as the benchmark to discuss fracture design changes and the effect on well performance. Case histories will focus on tight gas sands with reservoir quality ranging from 0.05 to 1.5 md with some pressure depletion. Multiphase flow effects in areas with higher water production will be investigated. Some discussion will focus on the details of calibrating fracture model inputs using open hole logs, radioactive surveys, sonic logs, production logging tools and mini-frac analysis. Results comparing post fracture well production, utilizing a pseudo 3D fracture design model and industry available production matching models, will show the effects of permeability, pressure depletion and multiphase flow effects on well performance. Understanding this information will allow the stimulation design engineer to better predict how geometry and fracture conductivity will alter well performance under varying reservoir conditions. With this knowledge, the engineer can better design ‘fit for purpose’ treatments, including those that may require extreme design changes in order to improve gas reserve recovery. Introduction The Wilcox (Lobo) trend in Webb and Zapata counties in south Texas is a series of geopressured, low permeability sands with an average depth from 5,000 to 12,000 ft. The Wilcox (Lobo) section consists of a sequence of stacked Paleocene age sands and shales overlain by the Lower Wilcox shale of Eocene Age. Extensive faulting, present in the Lobo section, has resulted in a slump complex of rotated fault blocks. The Lobo trend extends from Webb and Zapata counties to the south and west into Mexico. Permeability ranges from less than 0.1 md to 1.5 md. Figure 1 shows the location of the Lobo fields adjacent to the Mexico-USA border in south Texas.1 As an operator in this prolific gas producing area in south Texas, implementing effective hydraulic fracture treatments is a requirement in order for Conoco to economically produce the low permeability sands in the Lobo trend. This paper describes the engineering activities that were part of the development of a process to design and implement a pseudo three-dimensional (P3-D) fracture-modeling program in the Lobo trend in south Texas. The technique of hydraulically fracturing a formation to increase production rates and available reserves to commercial levels is a common practice within the petroleum industry. From industry surveys in the 1990's, approximately 56% of the wells drilled in the various geographic areas of the United States of America require fracture stimulation.2 The placement of a conductive fracture in the producing sands requires an optimal proppant fracture design process and proper field execution of the design. The engineering tools available for proppant fracture design have evolved during the past two decades. In the early 1980's, two primary mathematical models were developed and refined for modeling the complex hydraulic fracturing process. One model developed by Khristianovich and Zheltov3 incorporates the assumption of a rectangular shape in the vertical cross section of the fracture. A second model developed by Perkins and Kern4 and modified by Nordgren5 incorporates the assumption of an elliptical shape in the vertical cross section of the fracture. These two-dimensional (2-D) fracture models that assume a constant height vertical fracture have been widely used in the petroleum industry. Comparisons of these 2-D fracture models6 indicate that both models adequately agree with field data and that both models need to take into account changes in instantaneous shut-in pressure during treatments.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Wilcox Lobo Trend of south Texas contains vast quantities of natural gas in low permeability formations. Economic production from low permeability gas sands is possible through the use of hydraulic fracturing. Through the years, varying hydraulic fracturing techniques have been used to recover the gas from this trend. The success of fracturing techniques varies and depends on many factors. Several authors have demonstrated the importance of propped fracture conductivity in the production enhancement process. Without sufficient conductivity in the proppant pack, fracture fluid cleanup and adequate hydrocarbon production are difficult to achieve. The work presented in this paper will show the evaluation of these different completion techniques and products used in the Wilcox Lobo Trend by the authors. The work demonstrates the importance of fracture conductivity, supports previous work in other producing regions and presents some additional methods for achieving increased conductivity.The techniques, products and evaluation methods used in this paper can be used to benefit other operators in the Wilcox Lobo Trend as well as those working in other low permeability gas formations.