fax 01-972-952-9435. AbstractConoco drilled the Spa Prospect, Walker Ridge 285 #1
Conoco drilled the Spa Prospect, Walker Ridge 285 #1, in the Gulf of Mexico to a depth of 29,452' MD / 29,434' TVD. The Spa Prospect was a subsalt well encountering approximately 9,981' of salt. The Transocean Deepwater Pathfinder, a dynamically positioned drillship, was utilized to drill this well in 6,654' of water. Original planned total depth for the well was 31,600' MD / 31,000' TVD. This represented one of the deepest wells ever planned in the Gulf of Mexico. All geologic objectives were reached by 29,452' and drilling operations were terminated. This paper describes the challenges involved with planning the well, documents the execution, and concludes with lessons learned. The well planning included the following:Location selection criteria for avoiding shallow hazards while meeting geological objections,Pre-drill pore pressure and fracture gradient estimation,Hydraulics design and its relationship to drill string selection,Casing and wellhead program objectives,Landing string design,Lost circulation assessment,Mitigation of annular pressure in trapped annuli, andThe implementation of test rams to reduce BOP testing times. The execution section of the paper describes experiences encountered and the technologies utilized. Introduction The Deepwater Pathfinder spudded the Spa well on January 29, 2002, in 6,654' of water. Figure 1 presents the planned casing depths with planned contingency strings, and the actual casing depths for the original hole and the bypass hole. The original well plan was to drill to 31,600' MD / 31,000 TVD (all depths in this paper are MD unless otherwise stated). This well plan measured 10,121 on the Dodson Mechanical Risk Index, a Gulf of Mexico industry-benchmarking tool. The original wellbore was drilled to 27,504' when hole problems led to a decision to bypass. The bypass hole drilled a step out from 14,992' to 29,452' and achieved all of the geologic objectives of the well. The original hole required 146 days to complete and the Days versus Depth curve is presented in Figure 2. The bypass hole required 82 days to complete and the Days vs Depth curve is presented in Figure 3. The rig crews are to be commended for achieving zero Medical Treatment Cases and zero Lost Workday Cases during the 228 days and 325,000 man-hours. Well Planning — Location Selection Seafloor location selection was based on avoiding shallow hazards and the ability to set 22" conductor casing in salt prior to installing BOP and riser. Entering salt as soon as possible reduced the need for the contingency 18" and 16" casing strings. The industry has realized thick salt sections act as a casing string. Two different seafloor locations were evaluated. Location #1 had a relatively flat seafloor with negligible shallow hazards potential but had no salt. Location #2 was in a highly faulted seafloor graben with a 700' escarpment that had a shallow, thick salt section, Figure 4. Detailed shallow hazards analyses were performed at location #2 and minimal shallow gas and water flow potential were predicted. Location #2 was chosen due to the ability to set 22" casing into salt. Pore Pressure and Fracture Gradient One of the greatest uncertainties in planning the well was predicting pore pressure and fracture gradient below the thick salt body. Pre-drill pore pressure estimates above salt were derived by analyzing seismic velocities at or near the proposed well location. Pre-drill pore pressure estimates below salt were derived by correlating seismic velocities at the proposed location to seismic velocities in the nearby abyssal basin where salt did not exist. The pressure estimates were derived using stacking velocities from the abyssal basin projected up underneath the salt body. Unfortunately this technique was highly reliant on the quality of the seismic data, and could not fully take into account disruptions in sediments caused by the emplacement of salt bodies. These types of disruptions could cause reduced pore pressure and fracture pressure below salt.
There was a time when simply dumping some mica or nut hulls down a wellbore was a standard procedure for stopping mud losses. Certainly, these materials still work - for some applications. But, many of today's drilling operations bear little resemblance to that not-so-distant past. The industry is accelerating its activities in deepwater and depleted zones, both of which present narrow operating limits, young sedimentary formations, and high degree of depletion overbalanced drilling. All of these now-common conditions are ideal for fracturing and lost circulation. Drilling through and below salt formations presents a host of technical challenges as well. The thief zone at the base of the salt can introduce severe lost circulation and well control problems, often resulting in loss of the interval or the entire well. Controlling losses in this zone has proven to be extremely difficult. Very few lost circulation remedies have been successful, especially when using invert emulsion drilling fluids. The lost time treating severe sub-salt losses can last for several weeks, with obvious cost implications, especially for deepwater drilling operations. This paper reviews the methods applied to avoid lost circulation in the sub-salt thief zone, as well as in the subsequent intervals for a Gulf of Mexico deepwater project and discusses the time and cost savings obtained. For maximum success in these situations, emphasis has been placed on assessment and planning rather than individual lost circulation products. The authors will detail the Lost Circulation Assessment and Planning process that has been employed to explore and evaluate specific lost circulation problems and link them to existing products, systems and services. The integrative pre-planning process analyzes offset histories and formation data not only to identify risk zones but also to gather information on the exact fracture and pore size as well as fracture density. Afterward, detailed interval-specific decision-tree charts are developed for stopping losses encountered while drilling or tripping in. In addition to discussing the application of this Assessment and Planning process, the authors will outline the lessons learned on the deepwater project, featuring pre-planning issues geared toward ensuring circulation is maintained throughout the wellbore. Introduction and Problem Definition The problem of lost circulation was apparent in the early history of the drilling industry and was magnified considerably when operators began drilling deeper and/or depleted formations. The industry spends millions of dollars a year to combat lost circulation and the detrimental effects it propagates, such as lost of rig time, stuck pipe, blow-outs and, frequently, the abandonment of expensive wells. Moreover, lost circulation has even been blamed for minimized production in that losses have resulted in failure to secure production tests and samples, while the plugging of production zones have led to decreased productivity.1 When dealing with induced fractures the problem is even more complicated, as the shape and structure of induced formation fractures are always subject to the nature of the formation, drilling and mechanical effects, as well as geological influences over time. One condition of paramount importance in sealing induced fractures is having the lost circulation material (LCM) reaching the tip of the fracture.2 Related to the "breathing" tendency of induced fractures (to change shape and size as per wellbore pressure changes), "pressure buffering" is another condition that has to be fulfilled for effective sealing. Ideally, to stop the breathing tendency in a robust manner, the pills should be able increase the fracture gradient at a level sufficiently high to avoid re-opening the fracture during the subsequent drilling phases.2
Fluid trapped in the annulus of subsea wells can cause casing strings to fail. This condition occurs when casing annuli attain a closed-volume circumstance (when a well is cased, cemented, and head seals are set). During production, the heat transfer of the produced fluids to the casing strings causes the trapped fluid to increase in pressure. This condition is magnified in deepwater because annular fluids are cooler due to the cold deepwater environment. Laboratory testing indicates that thermal expansion of these fluids can cause trapped water- or oil-based fluids to increase in pressure above casing-collapse pressure, resulting in annular pressure buildup (APB). This paper outlines a simple laboratory procedure and resulting data to determine the resulting trapped-volume pressure. Data from eight fluid combinations are presented. The temperature change during testing is an increase from 80°F to 230°F. The testing relates to the conditions commonly found in deepwater Gulf of Mexico. The laboratory data obtained from this testing was used to design a spacer system for Walker Ridge 285 #1, a deepwater, subsea well located in the Gulf of Mexico. This paper also presents the job design and related procedure for the executed spacer system. Annular Pressure Buildup Introduction Cases of APB in annuli have been observed, documented, and reported for several years.1 On land, platform, and spar-type wells, the problem can usually be mitigated by bleeding off the annular pressure as required. However, subsea completions do not yet allow this option. Deepwater developments are extremely susceptible to APB when the differential between mudline temperatures and flowing-production temperatures exceeds 125° to 200°F. This increase in temperature significantly increases the pressure of a trapped volume of liquid. Laboratory testing shows that pressure increases exceeding 10,000 psi over placement pressure can be reached. In an actual well, the excessive pressure can cause casing and/or casing couplings to fail. The Definition of APB APB is the pressure generated by thermal expansion of trapped fluids as they are heated.2 When wellbore fluids heat up and expand in a closed system, the expansion causes high induced pressures. In most land and many offshore locations, this pressure may be bled off through surface-accessible wellhead equipment. In subsea completions, the primary annulus between the tubing and production casing (the A annulus) may be the only accessible annulus. Consequently, bleeding through the outer annuli (B, C, etc.) may not be possible. When a well experiences APB, two conditions are known to be present.3 First, a sealed annulus (or annuli) must exist. Commonly, a drilled formation is isolated in a cased well. Cement is circulated above the formation, and the top of cement (TOC) is frequently inside the annulus of the previous casing.3 When the wellhead is sealed, an isolated volume that is 100% liquid is created or trapped. Hence, the condition is termed as "trapped fluid" or "trapped fluid volume." Second, a temperature increase must occur. The trapped fluid will be heated by the drilling and production operations. When the fluid is heated by production, it expands and can produce a substantial pressure increase, which can be compounded if more than one annulus is sealed. Deepwater wells are likely to be vulnerable to APB because of the cold seafloor temperatures (approximately 40°F) at installation, in contrast to elevated subsea-wellhead temperatures that range from 180° to 200°F upon production. Various tools, such as casing design and temperature prediction programs, are available to evaluate APB.4,5 With the appropriate tools, steps can be taken to mitigate the risk associated with APB to help prevent casing failures. Common Mitigation Methods Existing solutions have been presented in past publications.6 Several of the following solutions are included in the literature:Cement shortfall (leave cement short of previous casing)Full-height cementing (cement filling the entire annulus)Preferred leak path or bleed port installation in previous casing stringSyntactic, crushable foam wrapEnhanced casing design (heavyweight and/or high-yield casing
fax 01-972-952-9435. AbstractFluid trapped in the annulus of subsea wells can cause casing strings to fail. This condition occurs when casing annuli attain a closed-volume circumstance (when a well is cased, cemented, and head seals are set). During production, the heat transfer of the produced fluids to the casing strings causes the trapped fluid to increase in pressure. This condition is magnified in deepwater because annular fluids are cooler due to the cold deepwater environment. Laboratory testing indicates that thermal expansion of these fluids can cause trapped water-or oil-based fluids to increase in pressure above casing-collapse pressure, resulting in annular pressure buildup (APB). This paper outlines a simple laboratory procedure and resulting data to determine the resulting trapped-volume pressure. Data from eight fluid combinations are presented. The temperature change during testing is an increase from 80°F to 230°F. The testing relates to the conditions commonly found in deepwater Gulf of Mexico.The laboratory data obtained from this testing was used to design a spacer system for Walker Ridge 285 #1, a deepwater, subsea well located in the Gulf of Mexico. This paper also presents the job design and related procedure for the executed spacer system.
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