Summary Point-source perforating has reduced fracture-stimulation expenses in the south Texas Lobo trend. Although the producing intervals frequently exceed 100 ft, the operator typically perforates the bottom 5 ft of the interval. Data collected during perforating are used to design optimized fracture-stimulation treatments. The optimized treatments average 55% less proppant than the jobs designed previously with conventional practices that had perforations across the entire pay interval. The new well's initial production and sustained performance has been higher than conventionally stimulated wells of similar potential. In addition, the point-source-perforated wells have produced significantly less proppant than similar wells with perforations across the entire pay interval. Point-source perforating has reduced the cost of perforating, proppant, fluids, equipment rentals, and cleanup. This case-history paper presents the following.Historical account of previous completion practices (limited entry, multiple-stage fracturing, and full-zone perforating).Discussion of the "perforating for stimulation" fracturing technique currently used.Comparison of production results.Formation-evaluation methods (logs and bottomhole gauges).Perforating methods (phasing, charges, and perforating interval selection).Results from a recompletion confirming that depletion has occurred. Introduction Perforating is a key component to the completion of most wells. Typically, the decision made about where to perforate is based on the location and the extent of the pay. The process of perforating is usually limited to choosing the appropriate gun with the best performance and scheduling the job. In the overpressured, low permeability environment of south Texas, a new perforating philosophy has been adopted, in which "perforating for stimulation" is the practice instead of "perforating for production." This new concept places the emphasis on the best perforation method for stimulation and obtains key fracturing parameters during the perforating stage of the completion. Experience shows that commonly accepted perforating techniques can cause well-designed stimulation treatments to fail. Cost Savings The operator has drilled approximately 150 Lobo wells over the last 5 years in the south Texas counties of Webb and Zapata. The experience gained over this period has reduced completion costs by U.S. $125,000 per well. These savings are derived from an overall change in the stimulation philosophy and the ensuing procedural changes this new philosophy created. Lobo Geology The Lobo formation is a member of the lower Wilcox group and has produced approximately 8 trillion ft3 of gas from two south Texas counties. The Lobo is a low-permeability, geopressured sandstone that was subjected to massive slump faulting at the end of its deposition. This created abundant faulting within the Lobo trend to the degree that individual blocks were created, usually 80 acres or less. This is a significant factor because each well is its own reservoir. Table 1 lists the typical reservoir parameters. Initial Development Consolidated Oil and Gas discovered the Lobo trend in 1973 with the N.H. Clark No. 1.1 Because of the complex structural nature of the Lobo and poor fracturing techniques, its full potential was not immediately realized. A major geological breakthrough occurred with the introduction of 3D seismic in the early 1990s. Two-dimensional seismic was used previously but resulted in a 72% success rate. With the introduction of 3D seismic, the success rate improved to 92%. Also, improvements in fracturing equipment, breakers, completion procedures, and 3D fracturing models have been significant factors in making the Lobo trend economic. Past Practices In the past, completion strategy was based on perforating every productive foot of pay derived from log analysis. Attempts to stimulate entire intervals were accomplished with large pad volumes, low Ottawa sand concentrations, and limited use of effective breakers. After the treatment, the wells were shut in overnight to allow the bottomhole temperature to break the thick, crosslinked gels. In later years, it was realized that all perforated layers were not being stimulated. The use of limited-entry perforating became popular in an attempt to stimulate the entire perforated section. This method limited the number of perforations to create excess perforation-friction pressure. In theory, this would increase the bottomhole treating pressure to greater than the pressure necessary to break down higher-stress zones, thus distributing the stimulation treatment to all perforated horizons simultaneously. The shortfalls of both these methods were recognized when cumulative production did not match predrill volumetric estimations. The next method involved limiting the treatment interval to one of the three primary Lobo sands and performing individual treatments on each sand package. This method showed improvements but still lacked the optimum results. Observations and a New Concept The factors leading to the new concept of "perforating for stimulation" were conceived from production-log results, the lack of success in adding perforations, tracer surveys, and information provided in the advance-stimulation technology work done by Aud, Wright, Holditch, and others.2 In an effort to better understand the completion effectiveness, production logs were run on a selected group of wells. The most revealing information was that the majority of the production usually came from a small interval, which was the best pay. Fig. 1 shows a production log from a hydraulically fractured well with the entire 100-ft interval perforated. More than 90% of the 1,800 Mcf/D was entering from only a 5-ft interval.

Fluids based on chelating agents have been developed for matrix stimulation of high-temperature sandstone formations. These fluids dissolve sizeable amounts of calcite and clays and maintain high levels of dissolved metal in solution over time with minimal precipitation. A series of field samples from high-temperature (149°C) sandstone reservoirs in a West African formation bear carbonate concentrations ranging from 2% to 37% (w/w). The effects of matrix treatment using a chelating agent-based system on these field samples were studied using coreflood and slurry reactor experiments.Linear coreflood test data show dramatic increases in the formation permeability after treatment with the chelating agent-based fluid. The improvement in permeability is ascribed to the removal of carbonate minerals and soluble clays, without secondary metal precipitation. Slurry reactor tests elucidated the kinetics of mineral dissolution in mechanically ground field samples. Treatment with acidic chelant fluids generated high levels of dissolved calcium, silicon, and aluminum that remained in solution over time. For comparison, conventional mineral-acid treatment of the field samples generated high levels of metals in solution that declined over the same period of time, which is indicative of secondary precipitation. The effectiveness of the chelant fluid for stimulation of this high-temperature formation was confirmed through increased formation permeability and high levels of dissolved minerals.* Now with Schlumberger.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFluids based on chelating agents have been developed for matrix stimulation of high-temperature sandstone formations. These fluids dissolve sizeable amounts of calcite and clays and maintain high levels of dissolved metal in solution over time with minimal precipitation. A series of field samples from high-temperature (149°C) sandstone reservoirs in a West African formation bear carbonate concentrations ranging from 2 to 37% (w/w). The effects of matrix treatment using a chelating agent-based system on these field samples were studied using coreflood and slurry reactor experiments.Linear coreflood test data show dramatic increases in the formation permeability after treatment with the chelating agent-based fluid. The improvement in permeability is ascribed to the removal of carbonate minerals and soluble clays, without secondary metal-precipitation. Slurry reactor tests elucidated the kinetics of mineral dissolution in mechanically ground field samples. Treatment with acidic chelant fluids generated high levels of dissolved calcium, silicon, and aluminum that remained in solution over time. For comparison, conventional mineral-acid treatment of the field samples generated high levels of metals in solution that declined over the same period of time, indicative of secondary precipitation. The effectiveness of the chelant fluid for stimulation of this high-temperature formation was confirmed through increased formation permeability and high levels of dissolved minerals.

The deposition of scale in the near-well formation and production string can result in a significant decrease in well productivity. Properly designed scale inhibitor squeezes can successfully prevent scale deposition and extend well performance. Even though most wells in the Tengiz field produce virtually water free oil (less than 1% watercut (WC)), inorganic scales have been observed in many of these wells. Frequent acid stimulations are required to maintain the optimum well performance. An extensive research project was initiated to reduce the need for frequent acid treatments and still maintain well deliverability at sustained rates. To identify an effective scale inhibitor product, inhibitor-brine compatibility testing and dynamic tube-blocking performance testing were conducted. Field application of the selected inhibitor in both low and high rate wells has verified the effectiveness of the squeezes. Treatment with the scale inhibitor attained sustainable well productivity and delayed the need for subsequent acid stimulation treatments. This paper will share the best practices in scale inhibitor design, inhibitor selection, identification of well candidates, the execution and post treatment surveillance stages. Case studies shown to illustrate the performance of scale inhibitor squeezes in Tengiz.

A new approach in advanced multiphase metering methodology designed for use in sour fields, quantifying H2S content in flow and properly accounting for it in the different phase rate measurements is presented. Flow metering in sour fields is challenging due to the need for containment of produced fluids and the effect of fluid properties in the interpretation of the measurements. The addition of H2S measurement provides additional information for production and reservoir monitoring and also yields improvements in flow metering, accounting for variations in fluid properties used for multi-phase calculation. Multiphase Flow Meters (MPFM) utilizing multi-energy gamma-ray fraction measurements are based on the ability of oil, gas, and water to absorb gamma rays of two different wavelengths. Adding an extra measurement at a third level of energy and leveraging the large contrast between the attenuation of sulfur and that of hydrocarbon and water components makes it possible to determine the mass fraction of H2S as an additional output. This technique was applied in Tengiz field, Kazakhstan, characterized by a high H2S content. In order to maintain reservoir pressure, improve recovery and utilize produced associated gas, a sour gas miscible flood pilot was started in 2007. The monitoring of compositional variation in producers is critical in the understanding of solvent (sour gas) distribution and thus in managing production-injection patterns to optimize plant throughput. Early field trials of the method were made comparing metered H2S content with surface PVT samples, confirming the accuracy of the methodology. The technology was then implemented systematically but strategically across the field. The in-line H2S measurement with automatic updates for variation in fluid properties was applied in two distinct areas: within the sour gas injection pilot area, where solvent levels vary, and outside the area where hydrocarbon composition is known to be homogeneous and constant. Long and short term tests with multi-rate well tests were conducted. Full datasets were collected from the MPFM to evaluate measurement stability and representativity under different flowing conditions and compared to results obtained without accounting for compositional changes. The results show a stable, accurate and continuous measurement of H2S content in produced fluid and an enhanced measurements of water, oil and gas rates comparable with PVT results. The in-line H2S measurement based on multi-energy gamma ray measurements is the only continuous H2S measurement technology available in multiphase flow conditions. It can be retrofitted to existing MPFMs, allowing to get additional parameter and enhanced stability of flow rate measurements where properties of produced fluid vary continuously. This paper will begin with a presentation of the theory, formulation and validation of the in-line H2S measurement and then go on to present a case history of the application in the Tengiz field, Kazakhstan for Tengizchevroil (TCO).