Successful Implementation of Well Management to Increase Hydrocarbon Production: A South Region of PEMEX E&P Case History
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAn integrated analysis of technical information from 459 wells that were shut in or having production problems within five Integrated Business Units in the Southern Region of PEMEX E&P, identified production increase opportunities of more than 145,000 STB/D of oil and 323 MMscf/D of gas. This paper presents the applied methodology and the results obtained from a project based on well management to optimize the recovery of hydrocarbons of the identified opport… Show more
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In the last 18 months, within the five Exploitation Integrated Assets in the South Region of PEMEX E&P, a well management program coupled with multidisciplinary teams has been implemented obtaining 24.5 MMSTB of oil and 40.1 Bscf of gas from workover of 372 wells that were shut in or had production problems. With the implementation and surveillance of this program in the field was possible for these assets to increase the production of oil to over 136 MSTB/D and gas to over 257 MMscf/D. These increases in production has made possible to maintain a production near to 500,000 STB/D of oil and 1,360 MMscf/D of gas in this region, offsetting natural production decline and loss of production due to a strong water invasion of wells. A profit-to-investment ratio of 16 has been obtained. Additional hydrocarbon production greater than 111 MSTB/D of oil and 196 MMscf/D of gas have been identified from 353 wells. The successful implementation of this program was based on the application of selected technologies that contributed to the increase of well productivity from the selected fields. This paper presents the applied methodology and the current results obtained from this well management program to optimize the recovery of hydrocarbons of the identified opportunities within these assets units with minimum investments. In addition to the value added of production increase through this well management approach, the following benefits were obtained: learning and applying the team work approach of well management, adaptation to a new cultural change of working as teams to solve difficult problems, training and transfer of diverse technologies, methodologies, and software technologies from the interdisciplinary teams to the technical personnel of PEMEX E&P, and specific well data information certified that can be used to evaluate reservoirs studies. Background PEMEX E&P in the South Region covers a surface area of 392,000 of square kilometers. This region has been conformed by five production integral assets including Bellota-Jujo, Cinco-Presidentes, Macuspana, Muspac, and Samaria-Luna as shown in Fig. 1. The producer reservoirs of these assets consist of Tertiary sandstones and Cretaceous carbonates which are naturally fractured rocks. The fields store all types of petroleum fluids that include dry gas, wet gas, condensate of gas, volatile oil, and black oil, with densities ranging from very heavy oils of 10 oAPI to superior quality oils up to 60 oAPI. However, 97% of the overall oil production in the region is light with densities greater than 30 oAPI. Hydrocarbon exploitation in the South Region started in April of 1953 with 3,354 STB/D. Peak oil production was achieved in December of 1979 with a production of 1.213 MMSTB/D as shown in the continue line in Fig. 2. Similarly, maximum natural gas production was reached at the rate of 2,853 MMscf/D in October of 1981 as shown in Fig. 2 as a discontinue line. The hydrocarbons exploitation history of the South Region can be characterized through six well defined production steps as shown in the top of Fig. 2. The first production step is defined from 1953 to 1972. This period describes the development and exploitation of the tertiary fields in Cinco Presidentes (Agua Dulce), Bellota-Jujo (Comalcalco), and Macuspana assets (Fig. 1). The biggest fields in the region were developed in the second step defined from 1972 to 1980. These fields are Sitio Grande and Cactus in Muspac asset, Antonio J. Bermudez complex in the Samaria-Luna asset, and Jujo-Tecominoacan and Cárdenas fields in the Bellota-Jujo asset. As mentioned before, at the end of this step the maximum oil production was reached. The third production step is defined from 1980 to 1990 where the main fields at the Muspac asset were developed such as Muspac, Chiapas-Copano, Giraldas and Agave. At the same time, Luna-Palapa fields in the Samaria-Luna asset were developed. In this step, on 1981 was recorded the peak of gas production as described before. In this step, between 1980 and 1984 severe oil production decline occurred estimated at 100,000 STB annually. In November 1984, oil production was recorded at 828,020 STB/D. Starting in January 1985 a oil production decline was observed in the amount of 35,000 STB annually.
In the last 18 months, within the five Exploitation Integrated Assets in the South Region of PEMEX E&P, a well management program coupled with multidisciplinary teams has been implemented obtaining 24.5 MMSTB of oil and 40.1 Bscf of gas from workover of 372 wells that were shut in or had production problems. With the implementation and surveillance of this program in the field was possible for these assets to increase the production of oil to over 136 MSTB/D and gas to over 257 MMscf/D. These increases in production has made possible to maintain a production near to 500,000 STB/D of oil and 1,360 MMscf/D of gas in this region, offsetting natural production decline and loss of production due to a strong water invasion of wells. A profit-to-investment ratio of 16 has been obtained. Additional hydrocarbon production greater than 111 MSTB/D of oil and 196 MMscf/D of gas have been identified from 353 wells. The successful implementation of this program was based on the application of selected technologies that contributed to the increase of well productivity from the selected fields. This paper presents the applied methodology and the current results obtained from this well management program to optimize the recovery of hydrocarbons of the identified opportunities within these assets units with minimum investments. In addition to the value added of production increase through this well management approach, the following benefits were obtained: learning and applying the team work approach of well management, adaptation to a new cultural change of working as teams to solve difficult problems, training and transfer of diverse technologies, methodologies, and software technologies from the interdisciplinary teams to the technical personnel of PEMEX E&P, and specific well data information certified that can be used to evaluate reservoirs studies. Background PEMEX E&P in the South Region covers a surface area of 392,000 of square kilometers. This region has been conformed by five production integral assets including Bellota-Jujo, Cinco-Presidentes, Macuspana, Muspac, and Samaria-Luna as shown in Fig. 1. The producer reservoirs of these assets consist of Tertiary sandstones and Cretaceous carbonates which are naturally fractured rocks. The fields store all types of petroleum fluids that include dry gas, wet gas, condensate of gas, volatile oil, and black oil, with densities ranging from very heavy oils of 10 oAPI to superior quality oils up to 60 oAPI. However, 97% of the overall oil production in the region is light with densities greater than 30 oAPI. Hydrocarbon exploitation in the South Region started in April of 1953 with 3,354 STB/D. Peak oil production was achieved in December of 1979 with a production of 1.213 MMSTB/D as shown in the continue line in Fig. 2. Similarly, maximum natural gas production was reached at the rate of 2,853 MMscf/D in October of 1981 as shown in Fig. 2 as a discontinue line. The hydrocarbons exploitation history of the South Region can be characterized through six well defined production steps as shown in the top of Fig. 2. The first production step is defined from 1953 to 1972. This period describes the development and exploitation of the tertiary fields in Cinco Presidentes (Agua Dulce), Bellota-Jujo (Comalcalco), and Macuspana assets (Fig. 1). The biggest fields in the region were developed in the second step defined from 1972 to 1980. These fields are Sitio Grande and Cactus in Muspac asset, Antonio J. Bermudez complex in the Samaria-Luna asset, and Jujo-Tecominoacan and Cárdenas fields in the Bellota-Jujo asset. As mentioned before, at the end of this step the maximum oil production was reached. The third production step is defined from 1980 to 1990 where the main fields at the Muspac asset were developed such as Muspac, Chiapas-Copano, Giraldas and Agave. At the same time, Luna-Palapa fields in the Samaria-Luna asset were developed. In this step, on 1981 was recorded the peak of gas production as described before. In this step, between 1980 and 1984 severe oil production decline occurred estimated at 100,000 STB annually. In November 1984, oil production was recorded at 828,020 STB/D. Starting in January 1985 a oil production decline was observed in the amount of 35,000 STB annually.
More than 70% of global oil production derives from mature fields. With current elevated prices, the revitalization and optimization of these fields are of great commercial appeal and interest. However, revitalization requires technologies and procedures for quick analysis and diagnosis of the field in addition to established technical solutions to help improve productivity and counter high levels of pressure and production decline. In 2013, in the southern region of Mexico, workflow integration for integral analysis of well productivity in mature fields and naturally fractured carbonate reservoirs, in combination with joint efforts of several product service lines and their technological solutions, have been key to identifying a portfolio of opportunities for well interventions. Of which, in a short time period, an increase to production of 1, 843 STB/D of oil was achieved, with only 54.5% of the proposed activity involving well services. In view of the energy requirements in the world and the low rate of discovery of new reserves, many companies have targeted maximizing the exploitation of mature fields. Therefore, this study intends to establish effective techniques, methodologies, best practices, and lessons learned developed by multidisciplinary teams performed in Mexico during the past eight years. This strategy has helped increase oil and gas production in areas where it was previously considered unlikely because of complexity issues, such as low pressures, low permeability, organic deposits, scales, advanced fluid, reservoir dynamics, and mechanical problems, among others. These efforts have resulted in highly successful solutions as well as added value to the national operator.
Water production represents a major challenge over the life of a reservoir. It is an important issue that directly affects hydrocarbon production and total reserves recovery around the world, especially in fractured reservoirs. In the south of Mexico, several naturally fractured, low-pressure reservoirs experience production disruptions when water from the aquifer channels invades oil-producing intervals through high-conductivity fractures. Water shutoff (WSO) treatments vary in design approach and efficacy percentage due to the difference in environments and formations that are subject to water breakthrough. For the last decade, in southern Mexico, different treatments have been performed without achieving the expected results in the described reservoirs. These treatments have included different types of fluids, including rigid setting gels; reactive pills; selective water setting cement; and conventional cement slurries, with or without the use of mechanical aids such as mechanical plugs, cement retainers, or coiled tubing for precise placement. One of the biggest challenges of WSO in these reservoirs is that the proposed treatments must have a high level of penetration into the natural fractures but, at the same time, they need to be displaced with nitrogen or light hydrocarbon derivatives to balance reservoir pressure, avoiding total losses of fluids into the highly conductive, low-pressure reservoir where they will lose the ability to control water flow from the aquifer. Using the synergies of the operator's reservoir knowledge, diagnostic workflow, and historical treatment records coupled with service company's treatment engineering technologies and local ability to manipulate and enhance existing WSO fluids, we exercised a systematic evaluation approach to the evaluation of past unsuccessful experiences and proposed adjustments to conventional treatments using rigid gel and conventional cement slurries for water control. Integrating the relevant findings following operator's water control diagnostic workflow with the study of relevant papers and methodologies used by oil companies around the globe, we proposed a different treatment strategy consisting in the addition of a reactive pill between the rigid gel and the cement to keep the treatment in the vicinity of the wellbore, viscous spacers between each treatment fluid to avoid contamination while traveling downhole, the inclusion of lost circulation fibers to create a fibrous net to promote cement filter-cake development and tailored treatment displacement with a predefined pressure according to reservoir condition that is close to the reservoir-equivalent hydrostatic pressure. During the past 2 years, the application of rigorous evaluation of potential candidates and the combination of these three enhanced WSO fluids in the described sequence reduced unwanted water production in two naturally fractured low-pressure reservoirs. In three field cases, the use of the proposed methodology led to a reduction of overall water production from an initial value between 70 and 100% to levels below 30%. Incremental oil production has been maintained in the best cases for more than 2 years after the treatments. The most significant result occurred in the first field case, where the water cut was reduced from 90% to less than 2% and oil production increased 12 times, obtaining a cumulative oil production of 240,000 bbl in a year. The documented methodology is a work in progress; we cannot replicate the technique exactly because each well presents challenges according to its construction and structural placement. Similar WSO treatments have been successfully applied in several wells in southern Mexico, increasing oil production and recoverable reserves. Continuous improvement efforts have also led to efficiency enhancement over time, as results and lessons learned are captured to be shared and replicated in similar reservoirs.
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