Case History of Reservoir Subsidence and Wellbore Damage Management in the South Belridge Diatomite Field

Abstract

Summary Production of fluids from the shallow, thick, and low-strength Diatomite reservoir in the South Belridge Field has resulted in reservoir compaction, surface subsidence, and numerous well failures. The most severe subsidence problems occurred while the field was under primary recovery, prior to implementation of waterfloods for pressure support. Consequently, a significant number of wells in the field have incurred casing damage, which proportionately limits the utility of these wellbores for continued production and routine wellwork operations. The nature of casing damage varies significantly depending on the location in the field, however casing shear ("kinks") generally produces the most severe problems in retaining full wellbore utility since it limits tool passage (e.g., packers, scrapers, etc.) and is not economical to repair using conventional milling tools. Since the mid-1980s, surveillance has been in place to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction, and wellbore damage in Exxon's operations of Section 19 in the South Belridge Field. The surveillance includes the use of ground elevation markers and a variety of production logs—several of which involve novel application and log interpretation. These data subsequently were used to develop and verify hybrid geomechanics and wellbore geometric models for assessing casing damage, identifying well operability and wellbore utility limits, and forecasting the remaining wellbore life from which a reservoir management plan and wellbore management operational strategies were established. A key ingredient in the implementation of this plan and operational strategies involved a cooperative tool development with a major oil tool service company to repair casing kinked wellbores as an alternative to re-drilling wells. In this article we provide a case history that describes the various synergistic reservoir and wellbore management activities designed to effectively mitigate subsidence-induced operational problems and the accompanying field benefits resulting from their implementation. Introduction The South Belridge Field is located in Kern County, California, in the San Joaquin Valley. The field is about 45 miles northwest of Bakersfield, California. Exxon operations are located in Section 19 which is nearly in the center of the productive portion of the Diatomite reservoir. Of the 504 acres operated by Exxon (three quarters of Section 19), the productive Diatomite comprises approximately 150 acres. Reservoir Geology. The Diatomite reservoir is a biogenic siliceous deposit, with a top of reservoir at approximately 1200 ft. The productive interval can be as great as 1800 ft, with the upper 800 ft referred to as the Opal A and the lower 1000 ft referred to as the Opal CT. The Opal CT is distinguishable by a higher degree of diagenesis. The average total porosity for the Opal A is about 58% and for the Opal CT is about 42%. The estimated average liquid permeability for the Opals A and CT is 0.2 and 0.1 md, respectively. The oil gravity is about 29°API. The Diatomite zones are overlaid with productive Tulare sands. The heavy-oil producing Tulare interval consists of unconsolidated sand with minor shale layers and is up to 1200 ft thick. The main Tulare shales are about 3 ft thick and are located approximately 700 and 900 ft deep. Production Operations. The Exxon property in Section 19 is developed on a 5/8 acre spacing using a line-drive waterflood. The wells are hydraulically fractured in multiple stages and produced from both Opals A and CT simultaneously. Current oil production is about 2700 BOPD from 130 producers, making use of 130 injectors for waterflood support. The current field baseline annual decline is about 6.5%. About 50 additional off-pattern wells currently remain idle. The active wells are located in the center of the trend; the remaining drill sites are available towards the east and west fringes of the productive area of Section 19. The majority of the wells in the field are completed with 5-1/2 in. casing and 2-7/8 in. production tubing. Producers are completed on the rod pump. Injectors are completed using either a full-body tension-compression packer or a slipless inflatable packer, and set at about 1400 ft to isolate approximately one third (200 ft) of Opal A (referred to as the UD1 zone). UD1 has slightly higher porosity than the rest of the productive interval and acts as a thief zone during injection. Recently, casing side injection was separately established into the UD1 zone. Reservoir Management Plan A reservoir management plan was developed for the Exxon operated acreage to optimize field profitability and long-term recovery of reserves. Inherent to achieving this goal is the need for a clear definition of the waterflood objectives. As a result, waterflood strategies were identified and improvements implemented based on measurements and analysis of water quality, production profiles, and well injectivity. Waterflood Objectives. The objective of the waterflood in the Diatomite is to obtain secondary recovery and to mitigate subsidence. For most of the Exxon operated acreage, the majority of the primary recovery has been realized, but the secondary reserves are substantial. Maintaining pore pressure is essential in mitigating subsidence. The high porosity diatomaceous formation has low compressive strength, resulting in severe compaction as the pore pressure is decreased. Compaction is monitored by the changes in surface elevation. Fig. 1 shows the subsidence rates in the center of the Exxon property that occurred during primary production from 1979 to 1987. In 1988 to 1989, production was curtailed to reduce subsidence and casing damage while producing wells were converted to injectors. Large scale waterflooding was initiated in 1989, and most wells were returned to production. The rate of subsidence was reduced from a high of over 2 ft/yr to 0.5 ft/yr by initiating the waterflood in a portion of the productive zones (in all but the UD1 zone). Recent waterflood improvements in the past year achieved zero net voidage, further reducing the subsidence rate to about 0.2 ft/yr.

On the use of quasi-static deformation to understand reservoir fluid flow

“…Deformation in the overburden can be problematic for offshore fields, such as Ekofisk (Sulak, 1991), resulting in platform and equipment damage. It is well known that production-related deformation can induce seismic activity and lead to well failures (Rouffignac et al, 1995;Dale et al, 1996). Displacement of the overburden can also impact the interpretation of time-lapse reservoir monitoring.…”

Identification of deformation pattern changes caused by enhanced oil recovery (EOR) using InSAR

“…The surface settlement has been reported by, e.g. Chase Jr, and Dietrich (1989);de Rouffignac et al (1995); Dale, Narahara, and Stevens (1996);Fredrich et al (2000); van der Kooij and Mayer (2002). Moreover, due to the local injection activities for the underground reservoir (Patzek 1992), the surface presents upward movements, as it has been shown in the literature such as Fielding, Blom, and Goldstein (1998); Wolhart et al (2005).…”

Geomechanical Analysis and Decision Analysis for Mitigating Compaction Related Casing Damage

“…Although well damaged in the overburden did concentrate around the reservoir flanks at Ekofisk (see Figure 4), and to some extent at Wilmington, experiences at Valhall, Arun, Belridge, Lost Hills, and Cold Lake suggest that overburden shearing damage is often more widely distributed. Observations of well damage at Belridge in particular demonstrate that with extensive development and compaction, localized shear damage at weak overburden layers can be very widely distributed over all portions of the field 4,7,11 .…”

“…Significant subsidence and casing damage have occurred at several fields throughout the world, including the North Sea, in the Gulf of Mexico, in California, Canada, South America, and Southeast Asia [1][2][3][4][5][6][7][8][9][10] . Problems can be particularly acute in deep offshore operations, where individual well costs often exceed 10million dollars and specific wells often target individual sand formations or fault blocks.…”