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fax 01-972-952-9435. AbstractThe South Region of Pemex Exploración & Producción (PEMEX E&P) is running a key development plan to improve the reservoir management, well productivity and ultimate recovery of all fields in the region. A fundamental part of this project is gathering reliable well production data on real time and on regular basics. The South Region of PEMEX E&P in cooperation with the technical team of PEMEX E&P performed a full study of available technologies in well testing to select a system that meet the needs of the region while simplifying the field logistic and minimizing environmental impact. PEMEX E&P selected the use of multiphase flow meters (MPFM). The program scope includes 8,064 measurements at well heads and collection manifolds during three years. The preparation and use of this MPFM program for multi-rate well tests was carried out with variable gasliquid ratio flowstream and systems capable to measure all types of flow regimes in fields producing from heavy oil to gas condensates. This paper describes the lessons learned about the practical reliability, accuracy, and operability of the MPFM meters. The paper illustrates with field results the benefits of implementing the multiphase metering in the region. MPFM meters have proved to be a reliable system to measure well productivity.

The objective of this paper is to present a process for improving the planning of gas field development. We discuss how static and dynamic characterization can be combined to help optimize gas field development. The main concepts, methodologies, and results are shown for an actual Mexican gas field. Static characterization centred on a series of seismic amplitude maps constructed from 3D seismic interpretation. Dynamic data included production data and initial pressure gradients which were useful in delineating individual reservoirs and establishing hydraulic communications between certain reservoirs. The seismic amplitude maps, modified by considering the dynamic data, improved the evaluation of reservoir quality, the estimation of drainage areas, original gas-in-place, and proved reserves. A strategy for the optimal field development was designed by using this combination of seismic amplitude maps modified with information from logs, cores, production, and pressure data. Introduction The subject gas field is located in the central area of the Veracruz basin southeast of Veracruz, Mexico. The field was discovered in 1921 with Well 1, which was drilled by a foreign company. The field is formed by many lenticular sandstones containing gas at abnormal pressures. The first producer well (Well 3) was completed in 1962 in Tertiary sandstones. The field has had a total of 24 wells drilled, in addition to Well 1. Fourteen wells are now gas producers (Wells 3, 4, 5, 6, 201, 402, 403, 404, 405, 406, 412, 415, 420, and 436), nine wells have watered out (Wells 10, 12, 13, 15, 101, 407, 414, 428, and Ma-1), and one well was lost because of mechanical failure (Well 102). Currently, the gas field is comprised of three main producing sandstones: the sandstones at the base of the Lower Pliocene (body "E" located at 1,600 - 1,680 m or 5,249–5,512 feet of depth) which began development in November 1969 with Well 5; the sandstones of the Upper Miocene (body "G" located at 2,050 - 2,250 m or 6,726 - 7,382 feet of depth) which began development in August 1966 with Wells 3, 4, and 6; and, the sandstones of the Late Medium Miocene (body "M" located at 2,500 - 2,700 m or 8,202 - 8,858 feet of depth) which began development in August 1988 with Well 201. Table 1 shows the well names, the reservoir, and fluid data for each producing sandstone. In 1999, a series of 3D seismic surveys were performed covering an area of 240 km2 (59,305 acres). The interpretation of the 3D seismic surveys allowed the construction of several seismic amplitude maps. These maps were used for detecting significant volumes of gas related to high seismic amplitude areas, while establishing geological models and delimiting stratigraphic features. The seismic amplitude maps were calibrated with reservoir and fluid properties as well as production data obtained through productive wells from different sandstones. Using these modified maps then led to an improved development plan for the field. The fundamental objective of this work is to present the methodology and results of the teamwork aspect of this integrated reservoir management study.

The objective of this paper is to present a process for improving the planning of gas field development. We discuss how seismic amplitudes and dynamic characterization can be combined to help optimize gas field development. The main concepts, methodologies, and tools, as results obtained are shown for an actual Mexican gas field. A series of amplitude seismic maps were constructed by using 3D seiesmic interpretation. These maprs were the essential part for detecting significant volumes of gas in place. Afterwards, calibrations of these maps with production data used in reserve evaluation studies, resulted in a low risk development strategy for the field. The example gas field is comprised of three producing sandstones at different depths (E, G, and M), and has 20 producing wells. Hydraulic communication and the drainage areas for each reservoir, in both E and M sandstones, were evaluated by using a combination of the amplitude in the seismic anomalies and production data analysis. A good agreement between the seismic amplitude and dynamic PETROLEUM SOCIETY CANADIAN INSTITUTE OF MINING, METALLURGY & PETROLEUMcharacterization of the pressure and production data was obtained, which improved the evaluation of the reservoir quality and the estimation of drainage area, original gas in place, and proved reserves. In E and M sandstones, four and three independent reservoirs have been detected, respectively. The E sandstone has an estimated value of 62 Bscf of original gas in place and the M sandstone has an estimated value of 110 Bscf of original gas in place. By using the reservoir dynamic model in combination with information of logs, cores, and production data, the economic optimum strategy for the field development was designed, that included the drilling of wells in areas with the best seismic amplitude.

This paper presents the applied methodology and results obtained from a new Well Management program to improve oil and gas recovery with minimum investments in certain asset units. In addition to the value of the increased production, the following benefits were obtained from this program: learning and applying the teamwork approach of well productivity improvement, adaptation to a cultural change of working as teams to solve difficult problems, and training and transfer of diverse technologies from the interdisciplinary teams to other technical personnel of PEMEX E&P. Introduction The South Region of PEMEX E&P has hydrocarbon production from five exploitation integrated assets including Bellota-Jujo, Cinco-Presidentes, Macuspana, Muspac and Samaria-Luna. The producer fields and reservoirs of these assets consist of Tertiary sandstones and Cretaceous naturally fractured carbonate rocks, and produce all types of petroleum fluids that include dry gas, wet gas, gas-condensate, volatile oil and black oil, with densities ranging from 10 °API to superior quality oils greater than 45 °API. Production in the South Region started in 1958, reaching a peak in 1979 at 1.213 MMSTB/D (continuous black solid line in Figure 1). Although there were several periods of new field development and workover activity, the oil production rate had declined to 463,995 STB/D by December 2004. The decline was caused by pressure depletion and also water invasion. The peak gas rate of 2,853 MMscf/D was in 1981 (showed as a broken line in Figure 1). The gas production rate decline was similar to oil, reaching 1,434 MMscf/D by December 2004. In the first half of 2005, as a result of this strong production decline and in order to comply with the production agreements of PEMEX E&P, the South Region Management designed and implemented a strategy to increase production and to reverse producction decline. The strategy involves priority management decision lines of action for the short-, medium- and long-terms of fields in development and/or mature fields. Short-term projects with minimum investment and excellent economic returns were given top priority based upon Management's hierarchical decision process guidelines. The investment project guidelines for the medium- and long-term projects include technical justification with economic studies based on the best practices established by Reservoir Management(1, 2), with the intent to optimize the exploitation of fields, i.e., maximize the recovery of hydrocarbons, minimize investments and reduce operating and maintenance costs. Under this scenario, different alternatives are evaluated in order to help optimize the decision-making guidelines necessary for reservoir-well-surface facilities to recover primary, secondary and/or tertiary reserves. On the other hand, in order to increase short-term production, it is necessary to plan and implement different schemes to manage and integrate wells from different fields. This is done with the objective of identifying opportunities that increase production easily, based on detailed static and dynamic studies of the productive zones close to and around producing wells, taking into consideration the production behaviour of the different fields, reservoirs and wells.