This paper presents the well clean-up experiences for the Kristin HPHT gas-condensate field. The paper covers the production clean-up campaign design, including up front planning, job design, technology selection and review of the test results vs. the objectives. The paper also addresses requirement for safety and environmental considerations. Traditional production clean-up methods and equipment has evolved over the years, adapting to changing authority and operator requirements, whilst striving to be more cost effective when it comes to operational cost, particularly in NPT terms. This has resulted in more complex equipment packages and much stricter environmental and safety requirements. This paper will demonstrate how the above was addressed for the Kristin field development project and how the results compared with the set goals. Descriptions of the key design criteria and technology selection for HPHT gas--condensate well clean-up is covered together with the evolvement of these over time through the well clean-up campaign. Introduction Kristen is an HPHT gas condensate field, situated in the Haltenbanken area outside Mid Norway (Figure 1). Kristin was discovered in 1996 and has been developed with four sub sea templates with a total of twelve wells (Table 3), producing to a semi submersible production platform (Figure 2). Completion of the first well was finalized on May 1, 2005, production commenced on 3 November the same year. Reservoir properties vary greatly over the field, and between the different reservoir zones. Highest permeabilities are found in the Ile and Tofte Formation with permeabilities in the Darcy range, while the Garn formation has permeabilities ranging from 1 to 10mD. Although Ile has better properties than Garn, Garn contains the major part of the field reserves. The virgin reservoir pressure is 910 bar at a depth of 4800 m TVD MSL. The fluid system is a retrograde gas-condensate system, with a GOR of approximately 1000 Sm[3]/Sm[3] and dewpoint pressure of 400 bar at reservoir temperature. In most of the wells, 7" liners have been run across the reservoir and then orientated perforation conducted. Most of the wells are drilled at high angles through the reservoir with 85º with a corresponding pay zone of 830 m being the record. The wells are perforated in oil-based mud. After perforating, a barrier valve is run above the liner hanger and the rest of the well is then displaced to clean completion fluids. Some of the wells are penetrating sands that are too weak for orientaded perforations to be used as a sand control measure. In these wells 5½" screens are run in oil-based muds before the barrier valve is run above the screen hanger. When the well is ready for start-up, about 50 m[3] of packer fluid (30/70 MEG/water) is located inside the tubing. 10–30 m[3] of oil-based mud, in many cases with considerable amounts of perforation debris is located below the barrier valve. The maximum shut-in pressure at the subsea well head after a flowing period has been recorded to 722 bar. For many wells flowing well head pressures have climbed well above 600 bar. (Table 1 contains additional field information.) To ease start-up of the wells towards the production facility, the operator demanded that the wells first be cleaned up towards the testing facility onboard Scarabeo 5 via a Workover Riser with Flowhead (3rd party supply). The overall goals for these cleanups were:Retrieve packer fluid and drilling mud from the well.Perform a short production test including a build-up to determine well and reservoir characteristics.Accomplish the technical goals without damage on humans, well/equipment or disposals to the environment.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn the past, in order to acquire real time, bottomhole SRO (surface read-out) data, either a downhole latching system or a download probe in close proximity to the transmitting device had to be used. An innovative SRO system that takes advantage of state-of-the-art developments in acoustic technologies, wireline, and wireless transmission, and yet, is compatible with tools conventionally used during drill stem test operations has now been introduced to the industry. This acoustic data-acquisition system provides access to real-time bottomhole data using either a wireline-deployed probe or via wireless acoustic signals sent through the production tubing. If the probe is used, this does not have to be close to the transmitting device in order to transfer the data to surface. Since the system offers the option of transmitting via wireline or via the wall of the testing pipe, the need for a probe or latching device along with the inherent problems that sometimes occur because the probe becomes stuck in the latch or mechanically fails can be eliminated. Finally, the additional rig time required for preparation and running of the probe to move the Acoustic Telemetry System (ATS) transmitter up to proper depth is saved, reducing operational costs. BackgroundEarly SRO systems required a mechanical downhole latch mechanism that required wireline in the hole for communication of the information from the downhole probe to the surface. For low-rate, low-pressure wells without any H2S or CO2, use of this type of system posed few potential problems. However, as the industry pursued testing of deeper, higher-capacity wells with greater concentrations of impurities in the well effluent, several safety issues were experienced with the use of wireline in the hole. In the late 1980's and early 1990's, various intermediate SRO systems used electromagnetic proximity probes to alleviate some of the safety issues and to improve the operational reliability of the SRO systems. However, these systems did not address the fundamental problem of using wireline-deployed signal pick-up probes. The realization of the advantages that a reliable wireless method of communicating downhole data to surface could provide is not new, and the oil industry began searching for a wireless method of communicating downhole data to the surface over 50 years ago. One of the first documented field tests was performed in 1948 to study the response at the surface of a downhole hammer. The results were not encouraging, and the project was dropped. As technology evolved, interest in wireless telemetry rekindled. Several companies revisited acoustic telemetry and developed research projects to address transmission of acoustic signals through tubing. Significant work by Barnes and Kirkwood in 1972 1 and, by Douglas Drumheller in 1988 2,3 helped the industry to understand how the acoustic waves responded to the tubing at various frequencies. Based on the principles laid by the earlier work, several companies now offe...
This paper covers the HPHT Gas-Condensate Exploration Well, 6406/9–1 on the Onyx SW prospect of the Norway Sea in the late spring of 2005 (Figure 1 and 2). The well test design and execution is presented in the paper, including; up front planning, job design, technology selection and review of the test results vs. the objectives for the well test. The paper also addresses how health, safety and environmental considerations were handled. Traditional well testing methods and equipment have evolved over the years, adapting to changing requirements. This has resulted in requirements for more complex data gathering over a shorter time with much stricter environmental and safety constraints. Coupled with increased needs for more accurate reservoir data for prospect evaluation, this has put a higher emphasis on upfront planning and improved technical performance together with extensive use of advanced fluid data gathering methodologies. This paper demonstrates how the above was addressed for the Onyx SW and how the results compared with the set goals. The application of the latest technologies in Gas-Condensate well testing was used on this job. Experiences from this were later used as the basis for other gas-condensate prospects, including those in the Russian sector of the Barents Sea. This paper focuses in particular on Fluid Sampling, Surface Well Testing and Subsea equipment. As several service companies were involved on this particular job, we have only included some general and limited content for the other services involved. Introduction The Onyx South West exploration well, 6406/9–1, was the second well to be drilled within licence PL 255 (Table 1). The first well 6406/5–1 in the Tott East prospect was drilled in 2002 to intersect sands of the Middle-Lower Jurassic Garn, Ile and Tofte formations2. Well 6406/9–1, Onyx SW, was planned as a vertical exploration well, with a HTHP pressure regime. The HPHT conditions in the well were marginal; however it was designed and executed as if under full HPHT conditions. Maximum anticipated surface pressure, with anticipated reservoir fluids to surface, was deemed to be less than 690 bar. Anticipated bottom hole static temperatures were anticipated in excess of 150°C. This well was drilled using a semi submersible drilling rig. The Geological objectives for the well were to test the Middle and Lower Jurassic; Garn, Ile, Ror/Tofte and Tilje Formations for the presence of Hydrocarbons (see Table 2 for details). The stacked reservoirs were sandstones with intercalated shales belonging to the Fangst and Båt Groups. Separate by shale intervals (Not, Ror) typically formed intra-formational seals. The main objective of the Onyx SW well test was to investigate the stacked formations Ile, Ror/Tofte and Tilje by conducting a multi-zone DST, with each interval being tested separately. Testing of two zones with a third as a contingency was planned to cover the formations of interest. Results from the well logging narrowed this to execution of a two zone DST, from a cost vs. benefit stand point. Key performance indicators One of the most important and basic requirements in the Norwegian and international oil industry is to have control of the activities offshore, to act on issues in a proactive manner, and to capture experience data. For the Onyx SW well the operator used their KPI system to the fullest in close cooperation and supported by the corresponding service company systems. The objectives set for the job were clear and concise;Zero LTI'sZero HPI'sZero Environmental incidents All well test objectives achieved and driven by the operator throughout the planning and execution phases of the job with full support from the service companies.
fax 01-972-952-9435. AbstractThis paper presents the well clean-up experiences for the Kristin HPHT gas-condensate field. The paper covers the production clean-up campaign design, including up front planning, job design, technology selection and review of the test results vs. the objectives. The paper also addresses requirements for safety and environmental considerations.Traditional production clean-up methods and equipment has evolved over the years, adapting to changing authority and operator requirements, whilst striving to be more cost effective when it comes to operational cost, particularly in NPT terms. This has resulted in more complex equipment packages and much stricter environmental and safety requirements. This paper will demonstrate how the above was addressed for the Kristin field development project and how the results compared with the set goals. Descriptions of the key design criteria and technology selection for HPHT gas-condensate well clean-up is covered together with the evolvement of these over time through the well clean-up campaign.
fax 01-972-952-9435. AbstractThis paper covers the HPHT Gas-Condensate Exploration Well, 6406/9-1 on the Onyx SW prospect of the Norway Sea in the late spring of 2005 (Figure 1 and 2). The well test design and execution is presented in the paper, including; up front planning, job design, technology selection and review of the test results vs. the objectives for the well test. The paper also addresses how health, safety and environmental considerations were handled.Traditional well testing methods and equipment have evolved over the years, adapting to changing requirements. This has resulted in requirements for more complex data gathering over a shorter time with much stricter environmental and safety constraints. Coupled with increased needs for more accurate reservoir data for prospect evaluation, this has put a higher emphasis on upfront planning and improved technical performance together with extensive use of advanced fluid data gathering methodologies. This paper demonstrates how the above was addressed for the Onyx SW and how the results compared with the set goals. The application of the latest technologies in Gas-Condensate well testing was used on this job. Experiences from this were later used as the basis for other gas-condensate prospects, including those in the Russian sector of the Barents Sea.This paper focuses in particular on Fluid Sampling, Surface Well Testing and Subsea equipment. As several service companies were involved on this particular job, we have only included some general and limited content for the other services involved.
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