An offshore operator had seven similarly drilled deepwater wells in the Gulf of Mexico that were reaching the end of their productive lifetimes and due to be decommissioned. A consistent and practical solution was sought to abandon the seven wells while meeting the regulatory requirements laid-out by the local compliance entity. Successful implementation would offer a potential solution to similar abandonment requirements globally. Due to the nature of abandonment work, some assumptions were required during the planning and preliminary cement design phase. Detailed well information would not be available until the rig was able to latch onto the wellhead and assess the well's condition. To address this uncertainty, and allow for flexible design, the base cement slurry for each section was designed with additives exhibiting low sensitivity to certain downhole conditions. These focused on keeping the slurry thickening time stable at a range of temperatures and slurry rheology consistent with surface to downhole conditions. The operator was successful in abandoning the seven wells as per the regulatory requirements, with 45 cement barriers put into place. Applying similar designs from one well to the next allowed for faster cement design turnaround and improved materials management. Using innovative solutions, the challenges controlling the slurry behavior at varying conditions were overcome. Cement additive concentrations were refined over the course of the project, but the iterative approach meant that fewer changes were needed later in the project due to the increase in operational experience and design data. Contingency cement systems were prepared ahead of, and continuously updated during, the project to address probable risks, adding to the database of slurries that could be referenced for future work and potentially increasing planning efficiency. Developing this standardized process approach to well decommissioning saved an average of 11 days per well, 32% of the time, when comparing the first three and the last three wells. Using a similar model, a more effective decommissioning plan can be created to conceivably allow for an increase in the scope of future abandonment projects to offset time savings. This process can be tailored to offshore and land wells around the world, especially where similarly behaving cement materials are locally available.

Polymeric rotary seals used in various oilfield equipment face challenging demands, including rotation for extended periods of time while sealing high differential pressure (?P). Such seals are typically mounted in a housing and compressed radially against a rotatable shaft, and prevent fluid from escaping through the clearance between the shaft and housing. One of the damage mechanisms that limits seal life is extrusion. High ?P forces seal material to extrude into the shaft-to-housing clearance. Factors such as shaft defection and runout overstress the extruded material, causing pieces to break away. Another damage mechanism is the accelerated adhesive wear that occurs when the PV (pressure times velocity) capacity of the seal material is exceeded for conventional rotary seals, or as hydrodynamic rotary seals transition toward boundary lubrication. In static sealing, extrusion is minimized by reducing shaft-to-housing clearance. In rotary sealing, the clearance has to be large enough to accommodate shaft deflection, runout, etc. Failure to provide adequate clearance results in heavily loaded metal-to-metal contact that damages the shaft, the seal, and the housing. This paper describes an innovative sealing arrangement that dramatically increases the PV capability of rotary seals, and summarizes key results from an extensive laboratory test program. Test conditions that were varied include shaft diameter, velocity, ?P, temperature, seal material, and lubricant. In the most extreme tests, each seal was exposed to a ?P of 7,500 psi and a velocity of 240 ft/minute for 1,000 hours, and survived in excellent condition. Potential applications for the new technology include rotating control devices (RCDs), washpipe assemblies, cementing heads, and hydraulic swivels. The new high ?P sealing arrangement is based on three technical advances: The seal is lined with a plastic having excellent high pressure extrusion resistance. The seal incorporates an advanced hydrodynamic inlet geometry that is sufficiently aggressive to produce hydrodynamic interfacial lubrication when plastic seal materials are used. Hydrodynamic lubrication with plastic seals significantly increases the PV capability of the seals beyond what is achievable with elastomer seals. An axially force balanced, radially pressure balanced backup ring having a very small clearance with the shaft is interposed between the rotary seal and the shaft-to-seal housing clearance. The extrusion resistance of the hydrodynamic plastic seal, combined with the axially and radially balanced backup ring, allows this rotary sealing arrangement to reliably operate at ~5 times the PV value of conventional high pressure polymeric seals for durations in excess of 1,000 hours.

ABSTRACT Drillstem testing is the primary method used to test and subsequently evaluate reservoir characteristics in exploration areas. From a properly run DST, reservoir pressures, formation fluids, and rate of production can be readily determined. In addition to these, Maximum reservoir pressure, average effective permeability, formation damage, formation phase changes, fluid phase changes, radius of investigation and depletion rates can later be added after the analysis of data acquired during testing. With the introduction of floating drilling, the basic tools used on land have been modified for use on anchored semi-submersible and drillships. New tools have been built or ad&d to the invezrory primarily due to vessel motion, and the extra safety required in offshore testing from a floating vessel. The past decade has seen the introduction of dynamically positioned drilling vessels in offshore exploration. These ships, for-the-most part, are being used in a specialized category. This would include: Operations in iceberg infested waters where conventional anchoring is limited. Deepwater exploration that is outside the range of all but a few specialized anchored vessels. In some cases, these vessels, cannot moor in very deepwater exploration that is presently being done. Remote exploration an a one or two well basis far from supply bases. Workovers or reentries into previously drilled wells for testing. Installation of subsea production trees. Any of the preceding operations could at some point require a DST. To date, the hydrocarbon reservoirs found in water depths exceeding 1500 feet, have been very limited. Therefore, operational experience gained from testing in deepwater and high volume flow rates of oil and gas have been limited to very few operators. INTRODUCTION Chevron Petroleum of Spain successfully carried out eleven deepwater drillstem tests, offshore Spain in the Gulf of Valencia. They were completed from September of 1977 to March of 1978. The dynamically positioned drillship, BenOcean Lancer, completed the testing of the three wells while it was under a long term contract to Chevron Overseas Petroleum, Inc. The water depths on the wells, Montanozo Dl, Cl, and D2, ranged from 1543 feet, 2209 feet, and 2448 feet, respectively. Flowrates on the tests were as high as 9800 BOPD in some cases. These are believed to be the deepest water, highest volume DST's run to date from a dynamically positioned vessel. The major problems that were encountered in the drilling, testing, and evaluation of these wells were: Excessive waterdepths. Massive loss returns and "no returns" upon penetrating the reservoir section of the well. These wells would alternatively "Flow" and go to a "vacuum" during drilling unless a "mud cap" was maintained. Defining an oil/water contact in a carbonate section. This was compounded by the well bore being saturated in some cases prior to logging the reservoir. An area where environmental variations during the late fall and winter are often difficult to predict. Difficulty in obtaining long core sections due to fracturing.

Abstract The development of a twenty-four inch diameter marine loading arm is presented in detail. The size of the arm, field servicing techniques and other features all combine to influence its geometric evolution. Illustrations are includedto depict major details. All information pertains to a pilot model arm. Introduction At the present time there are tankers of 326,000 DWT size in operation and berthing facilities are being designed to accomodate tankers up to the 500,000 DWT range. In order to prevent excessive "turn around" time of these super-tankers, cargo must be transferred at a proportionately increased rate. One method presently employed to load and unload liquid cargo is by use of marine loading arms. These arms, consisting of rigid pipe and swivel joints, form a mechanism between vessel and dock which compensates for ship';s movement while transferring the product. Currently, the largest all-metal, articulated marine loading arms in service are sixteen inches in diameter. With the existence of the super-tanker, there is ';a definite requirement for loading arms of larger diameter. The operational range of these arms must also be of increased magnitude resulting in relatively longer reaches. With arms of this size (and weight), field servicing procedures deserve special attention to minimize possible down-time. With the above in mind, the following criteria was established for such an arm: Diameter to be twenty-four inches to permit higher flow rates. Simplified swivel joint packing replacement to eliminate dismantling arm. Minimize arm width to accomodate anticipated spacing of ship';s flanges In addition, the following features would be incorporated: Arm to be fully counterbalanced in dead weight condition to reduce loading on ship';s flange and eliminate exterior handling facilities. Symetrical weight distribution to eliminate "built-in" base moment Reduction in dead weight by having fluid-carrying components act as structural members where possible. Development Layouts and studies were undertaken resulting in generations of concepts and ideas which eventually shaped the arm. Figure 1 is a general outline of the pilot model and serves to illustrate some of its aspects. Like many of its predecessors, the arm basically consists of a riser tower, inboard arm and outboard arm. The inboard arm is free to rotate about a vertical axis coincident with the riser tower centerline (riser axis) and about a horizontal axis near the top of the tower (trunnion axis). The outboard arm rotates through a vertical plane about a horizontal axis passing through the forward end of the inboard arm (apex axis). The above nomenclature is used hereafter to identify the swivel joints which permit this motion, i.e., riser joint, trunnion joint and apex joint. At the ship';s end of the outboard arm there is a combination of three swivel joints and elbows which permit freedom of movement of the ship in relation to the arm.