TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn Prudhoe Bay, Alaska, non-rig tubing repairs have become a viable alternative to rig workovers (RWO's) to provide an economic remediation for wells with production tubing by "A" annulus communication. Electricline (EL)-set patches can eliminate tubing communication at a significant cost savings and are particularly attractive in areas where RWO cost is significant, such as offshore, remote, or arctic locations. The advantage of tubing patch repair over a conventional RWO is that there is no need to pull tubing, resulting in the well being returned to service faster. Typical patch deployment costs are less than 5% of the costs for tubing replacement with a RWO. To date, 263 permanent and retrievable tubing patches have been set in 181 wells at Prudhoe Bay. This paper discusses the history of conventional tubing patches at Prudhoe Bay, recommended pre-patch diagnostics, and the use of 3-D advanced caliper viewing software. The paper also provides a systematic approach for the design and deployment of conventional tubing patches.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn Prudhoe Bay, Alaska, non-rig tubing repairs have become a viable alternative to rig workovers (RWO's) to provide an economic remediation for wells with production tubing by "A" annulus communication. Electricline (EL)-set patches can eliminate tubing communication at a significant cost savings and are particularly attractive in areas where RWO cost is significant, such as offshore, remote, or arctic locations. The advantage of tubing patch repair over a conventional RWO is that there is no need to pull tubing, resulting in the well being returned to service faster. Typical patch deployment costs are less than 5% of the costs for tubing replacement with a RWO. To date, 263 permanent and retrievable tubing patches have been set in 181 wells at Prudhoe Bay. This paper discusses the history of conventional tubing patches at Prudhoe Bay, recommended pre-patch diagnostics, and the use of 3-D advanced caliper viewing software. The paper also provides a systematic approach for the design and deployment of conventional tubing patches.

PUT River formation is an early Cretaceous reservoir in the North Slope, Alaska. Stratigraphically it lies above the Lower Cretaceous Unconformity (LCU) and below the Highly Radioactive Zone (HRZ). The reservoir sands are near shore face to shallow marine deposits with heavy bio-turbation. In the Prudhoe Bay Field the PUT River reservoir overlays the Sadlerochit interval, the main producing horizon. A number of the Prudhoe Bay development wells penetrate the PUT River reservoir and provide well control for defining the areal extent and thickness of the reservoir. Four lobes of the PUT River were appraised by recompleting existing Sadlerochit wells that penetrated PUT River. The oil filled south-east lobe is the target of the current development plan. A key uncertainty of the development plan was the transmissibility across the faults. Three dimensional (3D) stochastic reservoir models were constructed and matched with the appraisal production data to determine the OOIP. VIP simulation models were generated to construct a development plan for this reservoir to determine the ultimate recovery. Significant uncertainties remained with regards to (1) location, number and type (horizontal vs vertical) of injectors, (2) number of producers to use, (3) geologic properties (in terms of correlation length and direction and facies distribution), and (4) fault transmissibility that could impact the choice of the plan of development (POD). To select the optimal POD in terms of ultimate recovery a Top Down Reservoir Modeling (TDRMTM) process was set up. Several 3D models were generated to cover the geologic uncertainty. The TDRMTM process analyzed 960 discrete combinations of the above parameters. An optimal POD was selected from the analysis of the results. The range of possible recovery outcomes was also more clearly quantified. A development plan consisting of 1 horizontal injection well and 2 recompleted producing wells was chosen with an option to use two additional producers in the future. The injection well was drilled in early 2006 and the Southern Lobe of the PUT River began production in late 2006. Introduction Minor reservoir sands (with OOIP less than 50 MMSTB) frequently occur in the vicinity of large fields. Developing such sands when the major fields are matured offers an attractive incentive since production facilities usually are readily available and underutilized. However, economic development of these minor sands is a challenging affair. The uncertainty in reservoir parameters must be fully evaluated prior to implementing any development plan - before any cost is incurred - since even a slight error in uncertainty assessment can make the field development program uneconomic.