Pore and fracture pressure determinations are key considerations for the successful planning and drilling of North Sea Central Graben High Pressure High Temperature (HPHT) wells. Knowledge of these downhole pressure constraints can have a significant impact on drilling safety and economics. In this paper we present recent advancements to a previously presented methodology. Pore and fracture pressure is determined using wireline or MWD petrophysical data and an effective stress approach. The results have increased our understanding of overpressure generation mechanisms and hydrocarbon migration in this basin. Most traditional pore pressure estimation methods use a shale disequilibrium compaction model for their calculations. We assess these methods and propose that excellent results can be obtained by deriving porosity from density or deep resistivity data. This porosity, together with a lithology estimation from the gamma ray, are input into an Effective Stress Loading limb (ESL) model that calculates pore and fracture pressures through all major lithologies. Along the North Sea Central Graben axis there are two distinct pressure domains. These are separated by a low porosity (<5%) horizontal pressure seal within the Cretaceous Chalk Group. This seal occurs between 3.5-4km and is independent of stratigraphic level within the chalk. Above 3.5km, rapidly deposited Tertiary shales and Upper Cretaceous chalks are on the compactional loading limb. Here, moderate overpressures are generated by disequilibrium compaction. Below 4km, low porosity (5-10%) Mesozoic sediments are unloaded by fluid expansion mechanisms to produce extreme overpressures. The upper limit for the pore pressure is the fracture propagation pressure. When this is exceeded, hydraulic fracturing can occur and the fluids escape, allowing the fracture to close and pressure to build again. In this environment, primary hydrocarbon migration may be largely dependent on the rate of the hydraulic fracturing formed as a consequence of the extreme fluid pressures generated by fluid expansion. An understanding of these pressure generating mechanisms, together with improved porosity determinations, has led to more accurate pore and fracture pressure determinations. Implementing the results into well planning and drilling can help avoid many of the costly pressure related problems inherent to HPHT wells. Introduction Operators increasingly target deep HPHT prospects in many areas of the world. Accurate pore and fracture pressure determinations in these wells are key considerations. Optimurn mud weights and casing point selections are crucial to safe, efficient, and cost effective planning and drilling. Pressure related problems include well control incidents, lost circulation, differential sticking, reduced rates of penetration, and reservoir damage. These often lead to costly sidetracks, well abandonments, lost production, and even underground blowouts. The latter could lead to the expense of drilling a relief well and in extreme cases loss of rig and lives. Pressure related problems therefore represent a significant proportion of the high drilling costs associated with HPHT wells. In the Norwegian sector, average HPHT wells are four times as likely to have a well control problem, and incur an average of eight times the downtime of other exploration wells (Table 1). P. 53^
Summary Lime-based drilling fluids are commonly used in applications that require solids tolerance, low and stable rheological properties, resistance to contaminants, and inhibition to shales. The use of lime-based systems previously was restricted to environments in which temperatures were lower than 300°F because of excessive gelation of the mud at higher temperatures. Recent developments in drilling-fluid additives and solids-control equipment now permit the use of lime-based drilling fluids in high-temperature/high-pressure (HTHP) environments. Amoco Production Co. recently used a lime-based mud to drill a well offshore Texas in an HTHP environment. Predetermination of the drilling-fluid objectives contributed to the success of the operation. First, the drilling fluid had to satisfy U.S. Environmental Protection Agency (EPA) environmental discharge requirements. Second, stuck pipe and lost circulation, prevalent problems in offset wells, had to be minimized. Third, the fluid had to be stable to temperatures of 350°F and densities to 18.5 lbm/gal and to be resistant to CO2 and to saltwater flows. A high-temperature, lime-based system was developed and maintained to meet these drilling-fluid objectives. This paper describes the planning used to select the mud system, development of the formulation in the laboratory, laboratory testing to determine treatments during the course of the well, and the performance of the drilling fluid. This experience provided a unique approach to both the formulation and maintenance of a lime-based fluid used in hostile environments. Introduction Amoco Production Co., New Orleans Region, successfully used a lime-based drilling fluid in an HTHP environment. Mustang Island Well A-110, offshore Texas, was drilled to a total depth (TD) of 17,352 ft. The well was logged with a bottomhole temperature (BHT) of 338°F >350°F, interpreted by Horner plot) with an 18.5-lbm/gal mud density. Success of the operation was the result of careful well planning and prudent operational practices. Improvements made to a rather conventional lime-based drilling fluid to obtain a high-temperature/high-density (HTHD) formulation contributed to the well's success. In hostile drilling environments, many wellbore problems must be overcome to operate at maximum efficiency. In wells of this type, invert oil muds normally are used because they resist contaminants, provide wellbore stability, and are stable at high temperatures; however, oil muds pose environmental problems, and cuttings transportation and disposal can be expensive, especially offshore. If lost circulation occurs while an oil-based fluid is used, circulation is difficult to regain. Therefore, special consideration was given to use of a water-based fluid on this well. During well planning, offset well information was gathered to define operational problems and to determine pore pressures. Data from Mustang Island Well A-111 No. 3, drilled in 1986, were used to determine the casing program and pore pressures (Figs. 1 and 2) for the new well. Each hole section was then analyzed for problems common to that section of hole and recorded (Table 1). From these problems, a mud system was selected on the basis of the success of offset mud programs and overall economics. Four drilling-fluid objectives were then established for the well. The drilling fluid must (1) satisfy EPA environmental discharge requirements; (2) eliminate or minimize offset well problems; (3)remain stable at a temperature of 350°F with a density of 18.5 lbm/gal;and (4) be resistant to such contaminants as CO2and salt. Existing literature1–11 was researched to focus on the HTHP portion of the well. Research revealed that many of the typical dispersed fluids used in high-temperature environments contained a surfactant or a chromium compound to promote rheological stability.9,10 Such additives could prevent discharge of cuttings or mud into the Gulf of Mexico. The literature also showed that lime-based fluids could solidify as temperatures approached 300°F. This type of system was the most desirable because it directly addressed the problems listed in Table 1. The literature indicated that a high-temperature lime mud could be formulated with some new additives.1–4,6,7,11Laboratory testing was begun to formulate an HTHD lime-based fluid. The solids-control system on the rig was also evaluated to improve control of low-gravity solids. Such control was considered essential for any potential water-based drilling fluid to control rheological instability. Low-gravity solids or excessive additions of bentonite can lead to rheological instability, which, in turn, can cause lost circulation. The addition of two centrifuges was found to be cost-effective in controlling solids and was used during the drilling of the well (Table 2). From the literature and laboratory work, a lime-based fluid was developed that showed promise in addressing the drilling objectives while remaining stable under hostile environments (Tables 3 and 4). A plan was developed that required laboratory testing during the course of the well and direct communication between the Baroid Drilling Fluids and Amoco personnel to discuss real or potential problems. This paper discusses the reasons for the use of the lime-based flulid, the formulation of the drilling fluid, the testing to determine the proper product mix, and the results of these efforts. History of Lime-Based Muds Lime-based muds were used widely throughout the 1940's and 1950's. They were considered to be an inhibitive fluid with a tolerance to such common contaminants as salt, cement, and anhydrite. The rheologic properties of lime-based muds remain stable and low, even in a high-solids environment. They can be made with nearly any type of makeup water and easily maintained. As wells were drilled into deeper and hotter environments, however, severe gelation occurred; in the most severe cases, cementation of the mud occurred in the hole. Therefore, use of lime-based muds was restricted to environments with temperatures lower than 300°F and were discarded when a burned odor or severe gelation was observed during circulation after the mud was allowed to remain static in the hole. With more experience with lime-based muds, it was generally thought that a lower lime content could be used to increase the thermal stability of the mud at some expense toward inhibition. Thereafter, lime-based muds were classified as low-, medium-, or high-lime mud systems.
Since the Bureau of Safety and Environmental Enforcement (BSEE) released and implemented the updated version of the Code of Federal Regulations (CFR) in recent years, Operators now have the need to reenter wells that had been deemed as abandoned in the 1980’s, and perform operations to comply with the updated regulations. All of these wells have surface plugs (either cement plugs or cast iron bridge plugs) that require milling in order to access the wellbores to be abandoned. The use of a pulling unit is generally the method used for these abandonment operations. However, the risks of having pressure trapped below those surface plugs, and the ability to maintain well control during milling operations with the pulling and jacking units (PJU) poses a great concern to the Operators. Upon evaluation, Shell decided to use large outside diameter (OD) coiled tubing (CT) to mill the surface cement plugs and the cast iron bridge plugs. The use of CT enabled several operational advantages, such as the ability to handle potentially live well situations safely and efficiently, faster operations to mobilize (mob) from well to well, the use of larger bottom hole assemblies (BHA) with mills manufactured to drift the different casings 7", 9 5/8" and 10 ¾" inner diameter (ID), ensure optimal downhole motor (DHM) performance and to provide efficient removal of solids from the wellbore back to surface. This paper describes the CT operations performed on two shallow waters platforms projects in the GoM for Shell, where a total of 9 wells were intervened using 2 3/8" and 2 7/8" OD CT. The challenges encountered together with the developed solutions, equipment used, lessons learned are also discussed. Full compliance with BSSE regulations for well abandonment was the final result.
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