TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWells drilled in the deepwater Gulf of Mexico often experience problems with shallow abnormal pressured sands. Successfully drilling through these sands has been an industry wide problem. Shallow water flow problems have caused the industry to junk wells prior to evaluation of any or all well objectives and prevented using discovery and appraisal wells as producers. Shallow water flow problems also caused the loss of the wells at the first Ursa Tension Leg Platform (TLP) site.The Ursa field is located in the deepwater, 3800' water depth, Mississippi Canyon area of the Gulf of Mexico where shallow water flow problems have been severe. The sediments at Ursa contain massive, wet sands that are pressured above a normal seawater gradient at a very shallow depth below mudline. Different techniques have been used while drilling the discovery, appraisal, and development wells to attempt to successfully prevent and control shallow water flow problems. The severe shallow water flow problems at Ursa have been successfully overcome and the shallow batch set drilling program was completed at the second TLP site in mid-1998. Eleven wells, which required five casing strings, have been successfully drilled to below the base of the shallow water flow zones. This paper will discuss the problems encountered during exploratory, appraisal and development drilling at the Ursa field.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractConocoPhillips is developing the Magnolia field with a tension leg platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells produce primarily from thick, fine-grained, Pleistocene-age reservoirs. Due to the long lengths of the producing reservoirs and large variations in sand grain sizes/permeabilities, premium screens with shunt tubes in conjunction with cased hole frac packs have been used to complete the wells.The third well, A1ST1BP1, was completed using the same techniques as were successfully used on the first two wells. The A1ST1BP1 completion failed during initial unloading, allowing unacceptable rates of sand production. The well was worked over and the tubing with eight control lines and premium sand control screen with shunt tubes were retrieved/fished from the well with minimal problems. The retrieved screens had collapsed around the perforated base pipe. The well was re-perforated, new screens run and a second frac-pack pumped. When laying down the washpipe after the second frac-pack, erosion marks indicated an apparent second screen failure.A detailed examination of both A1ST1BP1 frac-pack jobs was conducted in conjunction with laboratory collapse and erosion testing of the premium screens. Collapse testing revealed the screen lost sand control at less than 1000 psi. The collapse rating stated by the manufacturer was greater than 7000 psi. The erosion tests demonstrated that inflow from supercharged reservoirs into the wellbore could erode hole(s) in the premium screen. Revised operational procedures were used in six subsequent frac-packs without any additional failures and zero to negative completion skins. This paper will discuss the failure modes of the two fracpack/premium screen sand failures, workover planning and execution to remove tubing with multiple control lines and fish screens with shunt tubes from close tolerance casing, as well as procedural revisions developed to successfully fracpack the subsequent Magnolia reservoirs.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractConocoPhillips (COPC) is developing the Magnolia field with a Tension Leg Platform (TLP) in 4674 feet of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM). The field was discovered in 1999 and appraisal wells were drilled in 2000 and 2001. Field development approval was obtained in 2001. The approved depletion plan and well construction strategy included drilling and casing wells prior to the installation of the TLP (pre-drilling), pre-completing and testing one well during the pre-drilling program, and completing the remaining wells from a completion rig installed on the TLP.The GB783 A2ST3BP1 well was successfully drill-stem tested (DST) from the Ensco 7500 dynamically positioned (DP) semi-submersible drilling vessel in June 2003 as part of the Magnolia field development. The pre-completion and DST operations overcame a number of challenges which included the frac-packing of a thick, fine-grained interval, and well testing from a DP semi-submersible drilling rig while simultaneously transferring produced hydrocarbons to a transportation barge moored to the rig.The objectives of the pre-completion/DST were to plan and execute the operations safely, validate the sand control design, determine well performance and reservoir properties, and verify the effectiveness of the completion procedures prior to the TLP rig completion program. This paper will focus on the extensive planning process and the operational aspects of performing a DST in a deepwater environment.

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ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4674 ft of water in Garden Banks (GB) block 783 in the Gulf of Mexico. Three wells were drilled at the eventual TLP site to discover and appraise the field prior to sanction of the development plan. Field development plans required drilling an additional six wells at the TLP site where a shallow water flow (SWF) zone is present. The development plan included batch drilling and casing the SWF interval prior to deepening any of the wells to total depth. The Magnolia batchset program was successfully conducted in 2002 using the Ensco 7500 dynamically positioned semi-submersible drilling vessel. The six well batchset program was drilled at less than the Authority For Expenditure (AFE) cost estimates with zero lost workday cases. The batch set program included jetting 36 in. casing to 246 ft below mudline (BML), directionally drilling a 26 in. hole to 3264 ft BML while building hole angles up to 17°, and running and cementing 20 in. casing with verified cement returns to the mudline. The SWF sand interval was drilled and cased without "Top Setting" a cemented casing string above the SWF zone. Although individual exploratory wells have been drilled and cased without top setting casing previously, the Magnolia field is the first deepwater field with a SWF zone to be developed in this manner. Pre-planning for the SWF zone addressed directional drilling issues, water base mud (WBM) design, cement formulation and placement procedures, and logistic supply to the drilling rig. Each well required three 89 ft joints of 36 in. casing, 81 joints of 20 in. casing, 40,730 bbls of blended WBM, and 6,760 ft3 of cement. Five supply vessels were used to provide logistic support for the operation. This paper will focus on the extensive planning process and the operational aspects of performing a batchset drilling program through a SWF sand in a deepwater environment. Introduction The well construction strategy for the Magnolia development wells included drilling the wells from a mobile offshore drilling unit (MODU) to total depth (TD) prior to the installation of the TLP. The "pre-drilled" wells would then be completed using a smaller, lighter completion rig installed on the TLP. This reduced the cost of the TLP due to the lighter deck loads than those needed for a full sized drilling rig and accelerated the production from the pre-drilled wells. The detailed planning and procurement of equipment for the pre-drilling program began in early 2002, immediately after project sanction. Remaining well construction personnel that were not already in place were selected and began planning the pre-drilling program. The completion design and pore pressure model determined the casing plan that was incorporated into the overall well design. Installing the 36 in. structural and 20 in. conductor casing strings for the development wells in a batch set mode at the beginning of the pre-drilling program was selected for the following reasons.Isolating the SWF sand with 20 in. casing and cement for all the wells before deepening any of the wells to TD would greatly reduce the cost impact if a SWF occurred that compromised the TLP site.Quickly capture efficiencies of repetitive activities by the drilling crews from the batch setting of the 36 in. and 20 in. casing strings. Taking advantage of coming down the learning curve quickly leads to significant cost savings.1The risk of a SWF occurring would be reduced since the rig crew would better understand and carry out the proposed plan of all six wells in a one month period versus drilling through the SWF zone once every six to eight weeks.To allow "leap-frogging" the subsea BOP between subsea wellheads during the pre-drilling program thus saving the cost and time of a round trip of the marine drilling riser and subsea BOP for every well.