Production of unwanted water substantially reduced
A North Sea well, originally drilled in July 1984, was completed as a sidetrack of the original well in August 1999. Initial production rates from the sidetrack were as high as 25,000 b/d, with minimal water cut. However, three months later, the water cut had risen to more than 50%. Subsequent well tests, over a period of nine months, confirmed that the water had risen to 65%, 72%, and finally 95%.
After the last well test, personnel from Halliburton evaluated the well by gathering fluid data to identify potential cross flows and to determine the bottomhole pressures for the development and planning of potential water shutoff operations. Following the workover, the well was shut-in prior to the water shutoff operations.
Evaluation confirmed that injection water had broken through in the highly permeable zone 1. In addition, water was cross-flowing into zones 2 and 3, below zone 1, but above the first fault block. Since there were two further sequences of productive sands below the two fault blocks, it was decided to perform H20 water shutoff operations in Zones 1, 2, and 3.
The treatments were pumped through 2-in. coiled tubing into the three target zones. Isolation of each zone was achieved with a retrievable bridge plug set below each zone prior to pumping the treatment volumes. After each treatment, a short production test was carried out to determine the effectiveness of the treatments prior to moving on to the next zone. The treatments achieved substantial shutoff across the three water producing zones with 225 bbl, 19.5 bbl, and 16 bbl of the solution being pumped into zones 1, 2, and 3, respectively. The total production of unwanted water was reduced from 15,700 b/d to less than 300 b/d - a reduction of more than 98%.
Patented membrane measurement method
A field-test and the implementation of a new technology that will improve formation evaluation at the well site will be performed jointly by Datalog Technology Inc. and Shell Internat-ional Exploration and Production. The unit, known as GasWizard, measures the amount of gas directly in the drilling fluid using a patented membrane measurement method. The present version measures the methane content of the drilling fluid, while the prototype device will provide a gas component analysis of the gas in the drilling fluid, allowing identification of the hydrocarbon type as the well is drilled.
Advantages of the new technology is quantitative gas data that does not suffer any of the problems of the traditional gas trap method of sampling. Shell will play a role in the testing, evaluation, and design of the prototype through the involvement of their research and operations personnel, providing testing facilities, feedback, and assessment of the tool.
Sonic measurement option
An acoustic reservoir measurement choice for deepwater and ultra-deepwater has been developed by Halliburton Energy Services. The wireline tool, known as WaveSonictrademark, and the 4 3/4-in. Bi-modal AcousTic (BATtrademark) logging-while-drilling (LWD) sonic tool is a third-generation crossed-dipole wireline tool and is a LWD-dipole sonic tool, providing compressional and shear measurements in fast and slow formations. The developer claims the concept gives operators wellbore evaluation answers from spud to total depth of the well.
Sonic solutions, regardless of formation conditions, with either the LWD or electric line tools, have raised the acoustic measurement standard in the oil and gas industry. The ability to obtain real-time data, such as pore pressure, seismic time-depth correlation, and bit wear predictions from the new sonic tool, and shear wave anisotropy measurements from the WaveSonic wireline tool, gives operators another complete reservoir solution.
The tool offers simultaneous monopole and crossed dipole measurements that can be used to determine the orientation of minimum and maximum principle stresses in conditions ranging from poorly consolidated, high-porosity sandstones to low porosity carbonates. This information can enhance 3-D stimulation design of both low-permeability fracture stimulation and sand control stimulation treatments, as well as give borehole stress data for geo-mechanical and borehole stability analysis.
The state-of-the-art dipole source technology and waveform processing methods used in this tool allow for the determination of acoustic anisotropy, which is used to enhance the geophysical 3-D seismic interpretation, as well as amplitude-versus-offset (AVO) analysis, by providing fast and slow shear wave travel times and their orientations. This mechanical design allows for drillpipe-conveyed logging in high-angle or horizontal wells and can be combined with openhole wireline tools.
The sonic tool is claimed to supply the same openhole evaluation benefits, including the ability to provide compressional and shear slowness logs, in both fast and slow formations. The dual-transmitter, dual-frequency, and dual-receiver-array configuration provides ultra-reliable measurement redundancy in various petrophysical, drilling, and geophysical applications. The new 4 3/4-in. tool design complements the existing 6 3/4-in. and 8-in. tools, completing the top-to-bottom acoustic solution.
Sand control for Enterprise in Brazil
The sand control equipment and services for the deepwater development of the Bijupirí and Salema fields offshore Brazil will be implemented by Halliburton. The development project will be the first to be operated by an international oil company Enterprise Oil Brasil Ltda. and its partners, Petrobras and Odebrecht, in the Campos Basin and is scheduled to start immediately. This expands upon the extensive Brazilian deepwater experience base.
The Bijupirí and Salema development plan calls for a total of 15 wells to be drilled, with nine production wells and six water injectors. The two fields are located adjacent to one another in the Campos Basin, some 90 km from Cabo de São Tomé in water depths ranging from 480 meters to 880 meters.
Time-cost, risk analysis in well construction
Well engineering and operations management software is high on the acquisitions list for a number of operators intent on reducing risk in well construction. Peak Group has developed a software application for well construction that applies time-cost risk estimation. Using Monte-Carlo probabilistic simulation techniques, the software evaluates the likely outcome of every risk scenario in order to estimate the time and cost of different well operational options.
The developers say the process allows users to test different operational options and identify areas of high impact, and is used to weigh the risk of a project's operation.
