In April 2005, the Chevron Joint Industry Participation Project (JIP) on Gas Hydrates organized a drilling and coring expedition to potential gas hydrate sites in Atwater Valley and Keathley Canyon in the Gulf of Mexico. In support of these activities, methods were developed to predict the mechanical and phase change stability of boreholes drilled in sediments containing gas hydrates. Models of mechanical failure and downhole temperature were constructed from seismic and log data for the wells in Atwater Valley and Keathley Canyon. Model results were compared with LWD caliper, image, and temperature logs in three boreholes. LWD logs were also used to assess drilling performance. Mechanical failure models compared favorably with deformation features observed in image logs in all three wells. An excellent match was also obtained between the modeled and measured downhole temperatures in Atwater Valley. However, for reasons that remain unknown, temperatures observed in the Keathley Canyon wellbore were generally lower than those predicted by the model. Time-lapse analysis of LWD data revealed that the equivalent circulating density (ECD) in Atwater Valley became abnormally high and coarse-grained solids were falling into the BHA annulus from uphole causing packoffs. These packoffs eventually caused the rotary to stall. Some evidence that the packoffs were caused by shallow water flows discharging large quantities of sand into the wellbore was found. Post-drill temperature simulations indicated that the LWD boreholes in Atwater Valley and Keathley Canyon were sufficiently cool to prevent hydrate from dissociating, owing in part to successful management of circulation rates in the borehole. It was also shown that loop currents at Atwater Valley helped to reduce the risk of dissociation. Introduction Gas hydrates are crystalline substances consisting of molecules of gas (e.g., methane, ethane, H2S) locked in a cage of ice1. They occur continentally in the sediments of permafrost regions such as in Alaska or Siberia, or close to the mudline in deepwater marine sediments, such as in the Gulf of Mexico or the Nankai Trough. Gas hydrates dissociate into water and gas when sufficiently heated or depressurized. Since vast amounts of gas are thought to be locked in sediments containing gas hydrates, there is growing international interest in gas hydrates as an energy resource2,3,4,5. Boreholes drilled in sediments containing gas hydrates are susceptible to a variety of instabilities. Thermal disturbances caused by drilling can lead to dissociation of gas hydrates. Instances of blowouts accompanying dissociation have been documented in the literature, particularly in permafrost regions6. It is likely that such incidents are under-reported, since operators are not always aware that they are drilling in gas hydrate zones. Since gas hydrates can enhance the strength of sediments, either by cementing the grains, or by acting as load bearing members in the pore space, the dissociation of gas hydrates during drilling can lead to a dramatic loss of mechanical competence. Furthermore, the expansion of gas accompanying dissociation may result in an abrupt increase in the pore pressure7 thereby weakening the sediment further. Thus sediments undergoing dissociation may be in an exceptionally weakened state when compared with surrounding formations.
This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible Pumps (ESP) in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains in excess of 1 billion barrels of STOIIP (Stock Tank Oil Initially in Place) in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately more than one- third of the oil production is from the ESP oil wells. To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields. The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 92 deviated producers. ESP was selected as the artificial lift method for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift method for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 12 horizontal producers are on ESP lift and the remaining four wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities. The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and sulphate reducing bacteria (SRB). 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field. A state of the art ESP control and monitoring architecture including ESP tornado plotting was developed and successfully implemented in the ICSS to remotely operate, monitor and optimize ESP well performance from the central control room within Mangala field and from the company headquarter located in Gurgaon.
Field XYZ located in the western offshore India is a multi-pay, multi-layered heterogeneous Carbonate reservoir having lateral discontinuities. Discontinuous layers and scale deposition and near well bore damage have led to multi-dimensional problems related to both upper and lower completions reducing ultimate field recovery. Workover attempts like re-perforation, additional perforations and plugging, artificial lift by electrical submersible pump (ESP) and secondary recovery by water injection were implemented to maximize the field recovery. However, any work over had only short term impact on production increase.Also, water injection and ESP performance were inefficient. Production History showed cyclic decline in production with time. Identifying and locating the layers' discontinuities became crucial in candidate selection and design of efficient injection pattern, artificial lift, completion and work over in existing and new infill wells. The following case study presents a workflow involving multi well geological, petro physical and time lapse formation pressure data and production logs to identify and locate lateral discontinuity within a pay of the field. As a result, the reservoir pressure support attempts using water injection methods were proved to be suboptimal. Furthermore, this workflow has been successfully implemented for identifying location of infill wells and candidate selection and design of wells to be completed with ESP. Seven future candidates for ESP were recognized. Additionally, locations of three new infill wells are identified and a strategic layer wise completion was designed and executed. Implementation of the results increased production from the field by 27%.
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