For openhole completions in a weak sand formation, the failure of completion tubing frequently occurs under the loading from formation subsidence resulting from production. This paper investigates the integrity of completion tubing in this environment using the 3D finite element method (FEM). An elastoplastic analysis was performed on four sets of completion tubing using 3D FEM. A porous elastoplastic model was used to model the mechanical behavior of a weak sand formation. The interaction between the completion tubing and the sand formation was modeled with frictional contact constraints. The inclination angles of the completion tubing are set at 15°, 35°, 50°, and 75°. With a given geostress field and pressure depletion from production, the numerical results obtained with the 3D FEM model include subsidence of the sand formation, distribution of the equivalent plastic strain, and von Mises equivalent stress within the completion tubing and its deformed mesh. The principal conclusions include: 1) major loading factors affecting tubing failure are the axial pulling force and the bending moment or normal pressure applied on the external surface of the formation subsidence; 2) including an extendable tubing section can release the axial tensile stress caused by production-induced formation subsidence, and thus keep the tubing intact; 3) various scenarios have been checked for a safe pore pressure depletion value with a variation of tubing parameters values. This work presents a best practice for estimating the completion tubing integrity under subsidence loading by using a 3D FEM tool.

Although extended reach and horizontal wells in deepwater fields have presented many difficult challenges, operators have been willing to accept the challenges because of the substantial net reserves that the deepwater fields offer. Unfortunately, although promising new technologies that target the more extreme conditions inherent to deepwater completions have been introduced, many operators have hesitated to try them because they lack proven track records. Fortunately, this has not been the case with one operator, and this paper will discuss the innovative technologies that were employed to successfully perform two "firsts" in gravel pack completions in complicated wellbore scenarios in a deepwater subsea field. The first job is the longest deepwater horizontal gravel pack (HZGP), run in Brazil. 75,000 pounds of gravel was placed in a 2,730-ft openhole section in 2,621 ft of water from the Ocean Alliance rig. The technologies that were instrumental in the success of this completion included special packer technology, a multi-position weight down tool with a HZGP pressure maintenance assembly, and a new type of sand control screen. Despite the long slant section (6560 ft @ 60 degrees) and openhole length, installation of the sand control completion was smooth, never reaching more than 10,000 pounds of drag. The second job used a realtime operations (RTO) data acquisition and visualization system during a gravel pack procedure. The system employs advances in traditional data management and networking to allow the personnel at the wellsite as well as all remotely stationed personnel to monitor critical well parameters so that immediate decisions on procedural changes can be made. The system allowed the service personnel and operator to monitor the job's execution and adjust pumping parameters as needed. This job illustrates the enhanced capabilities that can be gained from adapting innovative techniques to traditional procedures. The best practices from these completions will be used in all future jobs. This paper illustrates the importance and gains possible from considering new technologies and applying them where feasible. History of the Fields The deepwater subsea fields are approximately 100 miles east of Macae in Block BC-50B in Brazil's Campos Basin. Development of the two fields covers an area of 142 square miles that will be serviced by two floating production storing and offloading (FPSO) vessels that will receive production from 55 subsea wells. Water depths of the wells range from approximately 2800 to 3800 ft. Recoverable reserves for the first field are estimated to be at 867 million barrels of oil and 375 billion cubic feet of gas. The estimated reserves for the second field are 362 million barrels of oil and 141 billion cubic feet of gas.1 The location of the fields can be seen in the map in Fig. 1. The most prolific Brazilian turbidite reservoirs are included in the Upper Oligocene/Lower Miocene section. The oil is concentrated in seven oil fields.

Although extended reach and horizontal wells in deepwater fields have presented many difficult challenges, operators have been willing to accept the challenges because of the substantial net reserves that the deepwater fields offer. Unfortunately, although promising new technologies that target the more extreme conditions inherent to deepwater completions have been introduced, many operators have hesitated to try them because they lack proven track records. Fortunately, this has not been the case with one operator, and this paper will discuss the innovative technologies that were employed to successfully perform two "firsts" in gravel pack completions in complicated wellbore scenarios in a deepwater subsea field.The first job is the longest deepwater horizontal gravel pack (HZGP), run in Brazil. 75,000 pounds of gravel was placed in a 2,730-ft openhole section in 2,621 ft of water from the Ocean Alliance rig.The technologies that were instrumental in the success of this completion included special packer technology, a multi-position weight down tool with a HZGP pressure maintenance assembly, and a new type of sand control screen. Despite the long slant section (6560 ft @ 60 degrees) and openhole length, installation of the sand control completion was smooth, never reaching more than 10,000 pounds of drag.The second job used a realtime operations (RTO) data acquisition and visualization system during a gravel pack procedure. The system employs advances in traditional data management and networking to allow the personnel at the wellsite as well as all remotely stationed personnel to monitor critical well parameters so that immediate decisions on procedural changes can be made. The system allowed the service personnel and operator to monitor the job's execution and adjust pumping parameters as needed. This job illustrates the enhanced capabilities that can be gained from adapting innovative techniques to traditional procedures. Producing the fields is a massive undertaking and will add 30% to the current one million BOPD output from the area. The development project includes 55 wells of which 22 will be horizontal producers, 2 multilateral producers, 8 horizontal injectors, and 8 piggyback injectors. The 15 wells already in production will be recompleted.

The purpose of this project was to confirm the occurrence of and to characterize hydrocarbon gas diffusion through a swollen reduced-scale packer of oil swellable material. The extent and origin of extrusion at the ends of the scaled packer is a key measurement. A quantitative and qualitative analysis was performed to determine if the miscible gas mixture damaged the structure or compromised the capability of the elastomer / swellable packer to hold pressure. Two packers were swollen (separate fixtures) in diesel under conditions similar to downhole pressure and temperature. The test fixtures were limited to an internal pressure of 2000 psi. A 1900 psi differential pressure was applied across the two test samples using the swell fluid. A temperature of 72ºC was maintained for the test. A miscible hydrocarbon gas was then introduced (1900 psi) to one of the test samples to completely displace diesel from the high-pressure side of the test fixture. Pressure and temperature were maintained for approximately 35 days during which regular computed tomography scans were conducted to detect any changes in the density of the swellable rubber element.