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Collaborating Authors
Results
Abstract The Mexico South Region produces more than 520, 000 bopdl from mature carbonate reservoirs. These reservoirs have widely varying reservoir pressures, presence of natural fractures and temperatures up to 350 degF. The extremely high temperatures makes even more challenging the stimulation process with conventional systems resulting in excessive corrosion and very inefficient wormholing. An innovative solution, considering a chelating agent as treating fluid, has proved to be an effective approach to stimulate these reservoirs. The post treatment production in two different wells showed outstanding results with higher rates than previous treatments and the trend of the production declination was smoothed. This new stimulation solution aided with a good candidate selection has led it to be the preferred solution for HT wells. Well A was treated with 15.0 m3 of the fluid based on chelating agents as main system, with a solvent preflush and overflush. Previous to this job two stimulation treatments were performed pumping a mixture of conventional acid systems. In both occasions the production increased, however, the production declined to pre-treatment rates in a matter of days. When treated with the new solution the production increased 254 bpd with almost no decrease with time (monitored for three months), indicating a more efficient stimulation treatment, and greatly improved on the economical indicators. Well B was stimulated with 20.0 m3 of chelating agent fluid after three previous attempts using conventional systems. The production increased 726 bpd. Post-treatment behavior was the same as well A. Wells A and B showed an increased production of 1.7 KBD with a very limited production declination because of more efficient wormhole creation due to retarded reaction rates allowing a wide contact with the reservoir thus improving production performance, Np and eliminating post-treatment neutralization and testing surface equipment requirements.
- North America > United States (1.00)
- North America > Mexico (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Production and Well Operations > Well Intervention (1.00)
Abstract Much has been written about the deepwater Lower Tertiary Wilcox trend in the Gulf of Mexico, which spans hundreds of miles from Alaminos Canyon to Keathley Canyon to Walker Ridge (as well as adjacent areas). The estimated ultimate recoverable oil from these reservoirs is significant: 3 to 15 billion barrels. However, significant technical and reservoir challenges remain because of the water depth (typically greater than 5,000 ft), reservoir depth (typically greater than 20,000 to 30,000 ft below the mud line (BML)), and high pressures (greater than 20,000 psi bottomhole pressure (BHP)). Combining these issues with the thick, low permeability reservoir intervals (more than 1,000 ft thick in the tens of mD) requires new tools as well as new planning and optimization methods. These new planning tools require system-wide (holistic) integration across multiple domains and completion software applications to produce a truly optimized completion. This type of integration is provided by an automated software workflow. Previous papers have provided details about the benefits derived from the automation of operations, engineering, and production workflows in general. Lower Tertiary Wilcox reservoirs were deemed good candidates by a major service company to implement the automated workflow concept, given the reservoirs’ low productivity index (PI), high-cost wells, high pressure/high temperature (HPHT) technical challenges, and production uncertainty. This specific workflow seeks to optimize hydraulic fracture design within Lower Tertiary Wilcox reservoirs by stipulating the maximum net present value (NPV) that satisfies all well, completion, and reservoir constraints. Hydraulic fracture design is an example of what is largely a manual process that requires interaction with several software applications to obtain fracture geometry, production constraints, production sensitivity criteria, and NPV scenarios. When the goal is an optimized fracture design, the process is especially arduous because it requires iterative interactions with reservoir simulators, nodal programs, economics models, well tubular design systems, and stimulation design tools to arrive at a suitable design. Enabling coupled simulations technology, this fracture workflow provides a unique holistic combination of tools, which are linked to reflect the actual economic values.
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.50)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Play > Wilcox Play Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Play > Wilcox Play Formation (0.99)
- North America > United States > Gulf of Mexico > Gulf Coast Basin > Wilcox Trend Formation (0.99)
- (10 more...)
Abstract Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field development plans. All field data acquisitions from seismic, well logging, production and geomechanical monitoring to enhanced oil recovery operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model in advance of the field development and associated design and operations is essential for a successful implementation of such projects. Furthermore, utilizing a more reliable model can in-turn provide the basis in the decision making process for control and remediation of formation damage. One of the key identifier of the subsurface model is accurately predicting the hydraulic flow units. There are several models currently used in the prediction of these units based on the type of the data available. The predictions using these models are differing significantly due to the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions increasing the need for better models to enhance the predictions. A new approach has been developed in this study for predicting the petrophysical properties improving the reservoir characterization. Poiseuille flow equation and Darcy equation were coupled taking into consideration the irreducible water saturation in the pore network. The porous media was introduced as a domain containing bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis were performed on 17 Berea sandstone samples and the petrophysical properties were measured and XRD analysis was conducted. In addition, core permeabilities were predicted using a new permeability model and the results were compared to the measured permeability data. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers. Afterwards, by iteration and calibration of the laboratory data, the more realistic number of hydraulic flow units was determined accordingly. The same model was also implemented to a Cotton Valley tight gas reservoir in Northern Louisiana in order to determine the flow units. A comparative study shows that the new model provides a better distribution of hydraulic flow unitsand prediction of the petrophysical properties. Using the new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for both the Berea sandstone and Cotton Valley tight gas sand experimental data and the model predictions using the new permeability model show the wider range of applicability for various reservoir conditions.
- North America > United States > Ohio (0.69)
- North America > United States > Texas (0.68)
- North America > United States > Louisiana (0.67)
- (3 more...)
- North America > United States > Mississippi > Pond Field (0.99)
- North America > Mexico > Veracruz > Tampico-Misantla Basin > San Andres Field (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract The Captain Field which lies off the coast of Scotland is a shallow sandstone reservoir (3000 ft) comprising clean, unconsolidated sand with high permeability (up to 5D). The oil is heavy and bottomhole temperature very low (30 C). Throughout the development of this field (14 years) two of the main challenges have been control of unconsolidated sand and maximising production of the oil by water injection to maintain reservoir pressure. Particular attention has been paid to drilling and completion of the water injection wells. The drill-in fluid used was initially oil based mud but changing to water based drill-in fluid facilitated use of faster completion procedures. Initially, when using a water based drill-in fluid, displacement of the openhole to clear brine was always troublesome. This issue was resolved by the introduction of a new low temperature starch into the drilling operation. Adoption of the new formulation has facilitated a simpler, faster displacement operation and made it easier to test various techniques that are offered for filtercake clean up. Treatments, involving acetic acid released in situ, enzymes, sequestering agents, etc., provided questionable results. However, a breaker system that provides a delayed release of formic acid has recently been introduced and has led to a significant improvement in performance. New techniques have introduced significant benefits, for example: the improved starch shortened the completion process by at least several hours of rig time, the four most recently completed wells which were all treated with the formic acid system had an average initial Specific Injectivity Index that was about 50% better than the average achieved for the first five wells that were completed with oil based mud. The paper will present important aspects of the learning process on the Captain Field with particular emphasis on application of the new starch, and drilling/clean-up of the water injection wells.
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/29a > Ross Field > Ross Formation (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/29a > Ross Field > Parry Formation (0.98)
- (3 more...)