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Abstract The Canadian sedimentary basin has long been exploited using vertical well-completion techniques, sometimes producing from multiple formation zones. With recent advancements in horizontal drilling and multistage-completion techniques, horizontal wells are quickly replacing vertical completions as the completion method of choice in many unconventional oil and gas reservoirs. A popular completion method uses openhole isolation packers and ball-activated sliding sleeves to target specific intervals along the wellbore during fracture treatments. This allows multiple stages to be completed in short periods of time because fracture operations often do not have to be shut down to precede to the next stage, compared to the more traditional plug-and-perf completion technique. Microseismic mapping has proven effective in measuring fracture geometries, such as fracture half-length, height, azimuth, and stimulated reservoir volume. This paper outlines the workflow used in understanding and interpreting the created fracture geometry within individual openhole intervals of the openhole packer completion technique. The microseismic data proves that created fracture geometry can vary dramatically along the openhole section of a horizontal wellbore. Microseismic mapping also indicates that fractures do not always initiate across from the sliding sleeve port, but can in fact initiate anywhere along the openhole section, exhibiting, in some cases, multiple fracture initiation points. The microseismic-mapping results of this project were used to identify reservoir coverage along the horizontal wellbore as well as identify areas in the reservoir that were not sufficiently stimulated. By using information gained through microseismic monitoring, fracture models can be calibrated to match actual fracture geometry with modeled fracture geometry, resulting in a calibrated fracture model. Once defined, and using the well production history, the fracture model was used to forecast the future production of the well. Using the calibrated model can help operators optimize the number of stages, stage spacing, and fracture-treatment design to maximize reservoir contact and hydrocarbon recovery while minimizing completion costs.
Methodologies, Solutions, and Lessons Learned from Heavy Oil Well Testing with an ESP, Offshore UK in the Bentley Field, Block 9/3b
Brennan, Barny (Xcite Energy Resources) | Lucas-Clements, Charles (Xcite Energy Resources) | Kew, Steve (Xcite Energy Resources) | Shumakov, Yakov (Schlumberger) | Camilleri, Lawrence (Schlumberger) | Akuanyionwu, Obinna (Schlumberger) | Tunoglu, Ahmet (Schlumberger) | Hayhurst, Steve (ADTI) | Simpson, John (ADTI)
Abstract Due to increased hydrocarbon demand and technological advances, production from heavy oil fields in the United Kingdom Continental Shelf (UKCS) has become possible over the past 10 years. Despite substantial reserves in the UKCS with crudes less than 20° API, most of the activity has been confined to exploration and appraisal drilling. The main reason for the restricted activity has been the high uncertainty of the reservoir and fluid properties. Operational complexities inherent to heavy oil also limit the use of conventional appraisal-well testing technology. A method was developed to determine the most suitable technology for testing wells with heavy oil using an electrical submersible pump (ESP). The solution was applied in the Bentley field located in the UK sector of the North Sea in block 9/3b, on which final appraisal well 9/3b-6Z was flow tested in December 2010. The technical challenges included a short weather window, maintaining fluid mobility through the surface-testing equipment, oil and gas separation for metering, obtaining accurate flow measurements, and designing the most appropriate ESP system. A combination of technologies—dual-energy gamma ray venturi multiphase flowmeter, real-time monitoring, and a novel ESP completion—provided a solution that enabled successful well test execution. A multirate test reaching a final stabilized rate of 2900 bpd, with a subsequent period of pressure buildup was accomplished in less than 2.5 days with 10 to 12° API crude. A key lesson was how to obtain the quality of data that would enable reservoir engineers to extract with confidence a productivity index and perform pressure transient analysis for reservoir characterization. This success paves the way for development drilling to commence on the Bentley field at the end of 2011, but also demonstrates potential that can enable new heavy oil field developments.
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Greater Markham Area > Block 49/10a > Grove Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > Viking Graben > P1078 > Block 9/3b > Bentley Field > Dornoch Formation (0.99)
- North America > Canada > Alberta > Bentley Field > Anadarko 11C St. Paul 11-15-58-7 Well (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- (3 more...)
Comparative Study of Multistage Cemented Liner and Openhole System Completion Technologies in the Montney Resource Play
Wilson, Brad (Murphy Oil Company Ltd.) | Lui, David (Murphy Oil Company Ltd.) | Kim, James (Murphy Oil Company Ltd.) | Kenyon, Mike (Packers Plus Energy Services) | McCaffrey, Matt (Packers Plus Energy Services)
Abstract The Montney Formation Resource Play, which straddles the border between the Canadian provinces of British Columbia and Alberta, is considered by many to be one of the largest natural gas resource plays in North America. Original gas-in-place estimates for the Montney range from a minimum of 80 tcf to as high as 700 tcf. Despite horizontal, multistage stimulation being common practice to effectively exploit tight gas sand and shale reservoirs, determination of the optimal methodology and identification of the parameters that affect optimization have yet to be fully understood. This paper compares two different multistage hydraulic fracturing technologies applied in the Lower Montney Formation: cemented liner and openhole multistage system (OHMS) completions. In-depth analysis was performed on field data from 15 wells divided into two separate geographical areas within the same field. Comparisons included production analysis, lateral lengths, number of stages, stage spacing, proppant volumes, and pump rates. Additionally, operational time and cost comparisons on a per well and per stage basis for both technologies were determined. Based upon the field data analyzed, the application of OHMS completion technology is appropriate for the Lower Montney in the region of the play studied. Application of this technology for the wells selected in the two study areas resulted in both greater initial production rates and overall cumulative production than cemented liner completed wells. Additionally, less time was required to perform the fracture stimulation job when using OHMS technology as compared to cemented liners. Both the average total cost of completion and average cost per stage in conducting cemented liner jobs was higher than employing OHMS completions.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Petroleum Play Type > Unconventional Play (0.81)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
Abstract A completions strategy has been developed for improving both steam injection and production conformance in a thermal enhanced oil recovery (EOR) project by using intelligent well technology incorporating interval control valves (ICV), well segmentation, and instrumentation. The initial field trial is ongoing in the injector of a Northern Alberta steam-assisted gravity drainage (SAGD) well pair. The development of the completion technology suitable for thermal conditions, initial field trial results and the plans for further development are described. The application modeling shows that, depending on the level of heterogeneity present in the reservoir, a 45% reduction in the steam-oil ratio and an almost 70% increase in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam trap control can be applied in a segmented horizontal well pair. A cost-effective intelligent well completion solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance resulting in increased energy efficiency and oil recovery. The method being developed is also applicable to a wide range of other thermal EOR processes such as cyclic steam stimulation (CSS), steam drive, and variations, including, for example, those involving solvent additives. The initial field deployment in the injector well was primarily to prove the technology, to demonstrate the feasibility of modifying the steam distribution and to learn for future developments. A successful installation and commissioning of the intelligent completion has substantially validated the technology. Lessons learned are highlighted. Early injection test results and data show a significant increase in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of the steam injection in the well is underway and the results are discussed. The intelligent completion technology under trial, and proposed further developments, should enable more extensive use of downhole measurement and control in thermal EOR projects than has been possible to date.
Abstract Having worked in the field of Hydraulic Fracturing for forty years has allowed the author an opportunity for close observation of several cycles of conceptual applications of hydraulic fracturing. In 1970, the oilfield was using quite a plethora of varying frac fluids from Slick Water to heated asphalt, gelled diesel, emulsion frac fluids, linear gels, and a few crosslinked fluids, although there was some separation between applicable fluids for gas reservoirs and oil producers. By the mid-1970’s we had witnessed the death of heated asphalt as a frac fluid while emulsion fluids and Slick Water fracs were mostly put out to pasture. The age of the crosslinked gels had begun to dominate most of the fracture stimulation technology landscape, mostly because it was judged that this fluid type was able to suspend and place high concentrations of proppant. The emphasis on achieving high Fracture Conductivity with more effectively propped fractures became dominant. The 1980’s saw the industry fracturing technology and laboratory testing migrate toward more realistic test conditions for evaluation of packed proppant bed conductivity, especially with longer testing times, using elevated test temperatures, and by the latter part of the decade to incorporate the presence of frac fluids and their residue. However, in the late 1980’s, a few operators in tight sandstone applications in East Texas started re-inventing Slick Water fracs. Even though pumping rates and treatment volumes were 2x- to 4x larger than previous crosslinked gel fracturing treatments, they typically were placing only 15–25% of the proppant volume, yet claiming improved well economics. To add further consternation, in the next decade, George Mitchell found a unique application in the Barnett Shale for Slick Water fracs and eventually showed the world that some of these hydrocarbon-source shales can actually be commercial producers themselves. This paper will discuss much of the "frac fluid history" mentioned above, review historical highlights of laboratory fracture conductivity testing and field applications trying to illustrate the need for high conductivity as investigators began finding much lower predicted conductivity as they began seeking to emulate insitu reservoir conditions. Back then and still today, we continue to ask: Are we abandoning one of our most significant beliefs, Fracture Conductivity is King, every time we use Waterfracs?
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.71)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (48 more...)
Abstract Examples of an integrated approach for quantifying oil and gas production potential in different hydrocarbon windows of the Eagle Ford Shale are presented. The Eagle Ford basin is unique in that reservoir fluids range from black oil to dry gas depending on the geology, burial depth, and temperature. The main goal of this paper is to guide operators to an understanding of potential reserves and their distribution in the Eagle Ford through the use of our specialized analysis and methodology to estimate ultimate recoveries. Data from the Eagle Ford Shale was compiled and analyzed to gain knowledge about the basin. The geology aided in indentifying "sweet spots" based on the various thermal maturation windows. Also, recent drilling and completion activities were examined in addition to the observed production from public databases. The intent was to determine curent completion practices in different parts of the Eagle Ford and also provide insight on the relationship between geologic features and production trends. A rapid asset evaluation case study is presented to demonstrate technique and workflow that uses vintage vertical well data to provide an estimate of asset value and reserves for a typical horizontal well in the Eagle Ford. The results of the study identifies "sweet spots" of oil and gas production and indicates that 1) Eagle Ford production is related to the maturation windows, as well as structure; 2) the best wells in the Eagle Ford are in the thicker areas; 3) Austin Chalk production relates to the underlying Eagle Ford production; 4) different completions for different areas and types of hydrocarbons should be considered, and 5) data and knowledge integration is the key for rapid evaluation of asset value in the Eagle Ford Shale. Operators can use this information and technique to help 1) better understand the uniqueness of the Eagle Ford Shale, 2) optimize their completion design and field development plan, and 3) calibrate expectations on oil and gas reserves potential under their acreage.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Black Hawk Field > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Hawkville Field > Eagle Ford Shale Formation (0.99)
- (22 more...)
- Information Technology > Data Science (0.48)
- Information Technology > Artificial Intelligence (0.34)
Abstract Shale gas reservoirs have become a significant source of gas supply in North America owing to the advancement of drilling and stimulation techniques to enable commercial development. The most popular method for exploiting shale gas reservoirs today is the use of long horizontal wells completed with multiple-fracturing stages (MFHW). The stimulation process may result in bi-wing fractures or a complex hydraulic fracture network. However, there is no way to differentiate between these two scenarios using production data analysis alone, making accurate forecasting difficult. For simplicity, often hydraulic fractures are considered bi-wing when analyzing production data. A conceptual model that is often used for analyzing MFHWs is that of a homogeneous completion; in which all fractures have the same length. However, fracture lengths that are equal in length are rarely if ever seen (Ambrose et al., 2011). In this paper, production data from heterogeneous MFHW (i.e., all fracture lengths are not the same) drilled in extremely low permeability reservoirs is studied. First, the simplified forecasting method of Nobakht et al. (2010) developed for homogeneous completions is extended to heterogeneous completions. For one specific case, the Arps decline exponent is correlated to the heterogeneity of the completion. It is found that Arps’ decline exponent to be used after the end of linear flow increases with the heterogeneity of the completion. Finally, it is shown that ignoring the heterogeneity of the completion can have a great effect on the long-term forecast of these wells.
- North America > Canada > Alberta (0.29)
- North America > United States > Texas (0.29)