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Abstract Effective blowout preventer (BOP) requirements and well control policies are crucial in maintaining safe drilling and workover operations. These requirements/policies generally are tailored to the individual oil and gas operator's specific drilling environment. Changes in well profile, depth, temperature, pressure, hydrogen sulfide concentration, and safety margin may require changes in BOP equipment and well control. Saudi Aramco has recently revised their equipment requirements and well control policies in an effort to further optimize drilling safety and efficiency in the Kingdom of Saudi Arabia. This paper discusses changes in BOP stack arrangements, kill/ choke line requirements, replacement part criteria, elastomer application limits, and use of variable bore rams and shear blind rams. Also included are requirements for number of isolation barriers, pressure testing/maintenance, and minimum overbalance. A new tripping policy and shut-in procedure are also discussed, with the introduction of a new trip sheet and kill sheets. Specific well control policies are provided. Background and Introduction In 1994, Saudi Aramco resumed the Khuff gas development and Pre-Khuff exploration programs, which had been discontinued in the late 1980s. The associated activity level increased from one deep drilling rig in 1994 to twenty-two deep gas rigs at present. These gas wells range in total depth from 14,000' to 19,600' with bottom-hole temperatures of 300 to 350 degrees F. Bottom-hole pressures in some formations require as high as 162 pcf mud weight, while 90 to 100 pcf is typically needed to control the gas reservoirs. Shut-in wellhead pressure is approximately 6,000 psi. Hydrogen sulfide (H2S) concentrations in Khuff wells can reach 20% in some areas. The first Khuff gas horizontal well was drilled and completed in 1997. Thereafter, both horizontal and vertical wells have comprised the deep gas program. In 1998, two well control incidents occurred and prompted an in-depth operational review. As a result of this study and the continued emphasis on drilling deep gas, BOP and well control policies were revised. Additional revisions were also made as part of an ongoing optimization effort. BOP Stack All standard BOP stacks were reviewed to ensure the equipment complied with accepted industry practices and provided proper well control safety for all drilling/workover applications. Major stack design considerations were evaluated. Among these were pressure rating, component selection and arrangement. 1) Pressure Rating Pressure ratings of the standard BOP stacks are 10,000 psi (high pressure), 5000 psi (medium pressure), and 3000 psi (low pressure) as shown in Figures 1 through 5. Selection of the proper stack is determined by the โworst caseโ pressure containment, which occurs when all the drilling fluid has been evacuated from the annulus and only low-density formation fluid remains. Working pressure rating of the BOP and burst rating of the casing strings (with a 1.33 minimum design factor) were re-verified for all pressure applications to ensure a shut-in capacity greater than the worst pressure condition that could be imposed during a well control incident. No changes were required in the BOP pressure ratings or pressure applications. 2) Component Selection Main components of the standard BOP stacks include the annular preventer, fixed pipe rams, variable bore rams (VBR), blind rams, shear blind rams (SBR) and drilling spool. Components are selected by the maximum anticipated surface pressure, wellhead temperature, and H2S concentration.
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Qatar > Khuff Formation (0.99)
- Asia > Middle East > Qatar > Block 4 > Khuff Field > Khuff Formation (0.98)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment > Well control equipment (1.00)
Downhole Deployment Valve Addresses Problems Associated with Tripping Drill Pipe During Underbalanced Drilling Operations
Herbal, Steve (Pinnacle Operating Company, Inc.) | Grant, Rod (Pinnacle Operating Company, Inc.) | Grayson, Brian (Weatherford International Inc.) | Hosie, Dave (Weatherford International Inc.) | Cuthbertson, Bob (Weatherford International Inc.)
Abstract Underbalanced Drilling (UBD) is becoming more widely used and accepted because of the many benefits it provides such as:Limitations to the formation damage common in regular overbalanced drilling. Increased rates of penetration. Increased production rates and in some cases production while drilling which can provide early cash flow and enhance economics. However with these advantages come some drawbacks, the chief among which is the safety of the operation while tripping the drill pipe into and out of the well. Since the well is allowed to flow in traditional UBD operations a flowing or shut in pressure results in the well.Any significant pressure at surface requires that special precautions be taken during tripping operations to control formation pressure.Several techniques can be used among which are:Killing the well, this provides for safe tripping but can obviate the very reason for using UBD - formation damage can result. Flowing the well, this can lead to a dangerous situation if a sloughing formation forms a temporary bridge in the annulus. A Snubbing unit can be employed, this enhances safety but can add considerably to the operational cost. It is clear that a better and safer method is needed, since all the above carry disadvantages, and to this end a new method involving a downhole valve was conceived.In this approach a full opening valve which can be closed below the drill string while tripping, is deployed downhole below the "pipe light" depth and operated from surface by way of a hydraulic control bundle. This paper will review the concept of the Downhole Deployment Valve (DDV), its design and operation.The authors will go on to provide details of the first field trial of the a 7" 26lbs/ft full opening valve in a multilateral well which was drilled underbalanced in the James Lime play in East Texas/Northwest Louisiana. They will conclude that this device can provide major enhancement to a UBD operation without in any way compromising its advantages. Introduction Increased awareness of the degree of formation damage caused by fluid invasion into the reservoir during conventional overbalanced drilling techniques has resulted in a growing interest in the benefits offered by UBD.These techniques, though not necessarily suitable for all reservoirs, can have a considerable positive impact in such instances as:Depleted reservoirs where in-fill wells can be drilled with little or no damage. Highly permeable and fractured reservoirs where fluid invasion can be greatly limited and consequent degradation of permeability reduced or eliminated. Hard formations where greatly increased penetration rates can be achieved. However along with the many benefits offered by UBD techniques come some disadvantages, such as higher associated costs and increased perceived risk and safety issues.Perhaps the most significant such risk is during the normal process of tripping the drill string to change the bottomhole assembly (BHA).Since the formation is allowed to flow during UBD operations a surface pressure is ever present in the annulus which is controlled by a rotating control head.Once tripping begins and the pipe is being stripped through the wellhead, this pressure must be handled in some manner before a "pipe light" situation is reached.
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Drilling > Drilling Operations (1.00)
Abstract A new riser system consisting of a lift pump located a distance down in a conventional marine drilling riser with a separate mud return line from the lift pump and up is used to reduce the hydrostatic head of the drilling fluid in the bore hole. The upper section of the riser above the pump outlet is vented to the atmosphere. A lower mud level allows a higher mud weight to be used. However, determined by the position of the fluid level it will result in a lower pressure at the casing shoe. The hydrostatic head of the drilling fluid and the seawater will be sufficient to control the bottom hole pressure after an emergency disconnection of the marine-drilling riser at the seabed. The riser joint which houses the pump can be located anywhere in the riser section depending on water depth, formation pore pressure etc., typically 200 - 300 m below the sea level. The system also allows the bottom hole pressure to be quickly adjusted by simply adjusting the air/mud level above the pump outlet in the marine-drilling riser. P. 299