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Collaborating Authors
fracture treatment
Successful Completion of CO2-Foamed Hydraulic Acid Fracturing Pilot Campaign in Jurassic Gas Wells in Kuwait
Al-Muhanna, Danah (Kuwait Oil Company) | Ahmed, Zamzam (Kuwait Oil Company) | Al-Qallaf, Aliah (Kuwait Oil Company) | Ajayi, Ayo (Shell Upstream International) | Al-Othman, Mohammad (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Al-Salali, Yousef (Kuwait Oil Company) | Al-Ajmi, Moudi (Kuwait Oil Company)
Abstract Jurassic Gas Field Development Group (GFDJ) of Kuwait Oil Company (KOC) completed the first ever CO2 foamed acid frac pilot campaign in four Jurassic sour HTHP wells. This innovative technology was utilized for the first time in KOC's history safely and effectively with exemplary well performance. GFDJ had been pursuing the CO2-foamed acid fracturing technology since 2019 with the objective of improving the stimulation and hydraulic fracturing efficiency in the Jurassic Middle Marrat formation. CO2-foamed acid fracs have several advantages over other stimulation techniques: CO2 is a miscible and non-damaging fluid which blends in water and also mixes with hydrocarbons. Pumped as a liquid and slightly heavier than water, leading to lower treating pressures due to heavier hydrostatic head. Effective in treating lower-pressured/partially-depleted, good K.H (permeability-height function) carbonate reservoirs. Reduces water-based gels and overall frac-load volume by the percentage of CO2 pumped in the frac fluid system (40% by volume is utilized in this pilot). Energizes the frac fluid and stays in solution until it heats up to gas. This property ensures the frac load recovery is achieved throughout the flowback. Eliminates the need to activate the well after the frac with CT/N2 applications potentially saving time and money to KOC. Has potential to lighten up the heavier ends of the hydrocarbons due to its miscible properties, hence may help with better hydrocarbon inflow. Creates stable foam structure with the frac fluid, increasing the frac fluid viscosity hence has the potential to generate better frac geometry and larger stimulated rock volume (SRV). A four-well campaign was completed within 12 months period. Three different monobore completion wells and one 3-1/2″ tubing with 5″ liner completion well were fracture-treated using an average of 40% downhole quality CO2-foam pumped at an average rate of 30 bpm. Different service companies and their fluid systems, as well as their operational capabilities were utilized in operations with exemplary clean up and production test results that surpassed the expectations of the asset. Additionally, pumping cryogenic CO2 at high ambient desert temperatures of September in Kuwait, safely, and operationally effectively is a major milestone and achievement in itself. This paper summarizes the design, operational, well clean-up and production performance details of the CO2 campaign. Learnings of the GFDJ asset will be shared in order to benefit from the learning curve that KOC went through in implementing this strategic application. Success of novel CO2 stimulation technique is critical for the GFDJ asset to continue expanding its production capacity in next 2-3 years while maintaining the strong production plateau achieved in 2021. Future plans of the assets will also be discussed to ensure cross-boundary opportunity realization will be possible in the industry for the region.
- Geology > Rock Type > Sedimentary Rock (0.68)
- Geology > Geological Subdiscipline (0.47)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Upper Burgan Formation (0.94)
- (2 more...)
ABSTRACT: Investigative models based on the Linear Superposition Method (LSM) are used to explain the changes in the stress-field induced during three phases in the well life-cycle subsequent to the initial state (Phase 0), the fracture treatment operation (Phase 1), the flowback period (Phase 2), and the subsequent production period (Phase 3). New LSM models, integrated with spatial pressure decline modeled with 2D Gaussian equations, show time-series of the principal stress evolution near the hydraulic fractures. Two generations of stress reversal can be distinguished. A first reversal of the principal stress directions occurs during Phase 1, and is accompanied by amplification of the tectonic stress anisotropy. A second generation of stress reversal occurs during Phase 2, when the pressure-load of the fracture treatment intervention is removed from the multi-fractured well system; slow attenuation of the stress anisotropy occurs near the system due to the flowback. Further changes in stress magnitudes occur during Phase 3. The practical relevance of our results is the possibility to quantify the near-well changes in (1) the orientation and (2) magnitude of the local principal stress relative to the far-field stress, as inputs for commercial simulators to design the optimum trajectory and treatment plan for infill wells.
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
Delineating the Multi-Stacked Domanik Play in the Volga-Urals Basin, Russia
Shaw, Kevin (APEX Petroleum Engineering) | Randolph, Theodore (APEX Petroleum Engineering) | Anthony, William (APEX Petroleum Engineering) | Harkrider, John D. (APEX Petroleum Engineering) | Gendelman, Igor (Wavetech Energy)
Abstract This paper shows the importance of an integrated, multidisciplinary approach to exploiting the unconventional Domanik Play in the Volga-Urals Basin in Russia. A combination of understanding the reservoir and applying different completion techniques is necessary to verify the best way to drill, complete, and produce the basin. In 2012, DirectNeft drilled the first well specifically targeting the Domanik interval in the Volga Ural Basin. This discovery well tested oil from multiple horizons within the 350+ m (1150’) thick "Domanikoid" section. In the broad Upper Frasnian interval, Well A was the first successful hydraulic fracture treatment in the Domanik. The subsequent Well B, seven miles to the northwest, penetrated a largely identical Domanik section and was also fractured and tested in multiple horizons, including the Upper Frasnian. Well tests, logs and core analysis have identified two primary and two secondary productive intervals within the Domanik. These two wells provided the first sets of modern logs in the area, which are critical to better understand the reservoirs. In addition, the coring of key intervals and extensive analysis of those cores have proven invaluable in understanding the nature of the reservoirs. Existing well control and seismic data clearly indicate the thick section of Domanik rocks extends throughout the area. The presence and viability of oil saturated Domanik low permeability reservoirs has been confirmed by the two wells. Oil flows have been recovered from perforated intervals of the Tournaisian, Zavolzhian, Famennian and Upper Frasnian. Based on these exploration findings, subsequent operations expanded the project by drilling four horizontal wells in 2017-2018, three of which have been completed. Objectives are multi-fold and included further delineation of the four productive intervals by refining the understanding of geologic, petrophysical and geomechanical models that influence the completion and stimulation operations, ultimately impacting production. Early results from the completed wells have shown a rapid improvement in production results, showing that the multidisciplinary workflow is successful. Future tests incorporate significant increase of entry points to further prove the success of the play. This paper describes the methodology and modifications implemented based on improved understanding of the reservoir, including the use of multi-stage completion techniques. Also discussed are operational issues related to implementing state-of-the-art completion techniques including sliding sleeves, coil-tubing operations, jet cutting operations and plug and perf operations.
- Europe > Russia > Volga Federal District (0.90)
- Europe > Russia > Northwestern Federal District (0.81)
- Geophysics > Borehole Geophysics (0.93)
- Geophysics > Seismic Surveying (0.86)
- Europe > Russia > Volga Federal District > Volga Urals Basin (0.99)
- Europe > Russia > Northwestern Federal District > Volga Urals Basin (0.99)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Romashkinskoye Field (0.94)
- Europe > Russia > Volga Federal District > Bashkortostan > Volga Urals Basin > Arlanskoye Field (0.94)
Microseismicity and Dry Shear-Slip in the Stimulated Rock Volume During Fracture Treatment in Shale Wells: Analyzing Data From the Hydraulic Fracture Test Site (Permian Basin) With the Linear Superposition Method (LSM)
Weijermars, R. (King Fahd University of Petroleum & Minerals) | Wang, J. (Hanyang University)
ABSTRACT: This study analyzes 130,286 microseismic events recorded during treatment of 434 fracture stages in the Wolfcamp Shale Formation at the DOE Hydraulic Fracture Test Site (Reagan County, West Texas). Three principal results are presented: (1) Detailed LSM models of the shear-slip and tensile failure regions, near the advancing fracture tips, are developed for both single and multiple hydraulic fractures. These models give comprehensive insight in the extent and migration of active shear-slip zones in the stimulate rock volume (SRV) during fracture treatment. (2) The HFTS microseismic data is analyzed in detail to characterize the dimensionless moment magnitudes (Mw). Probabilistic mean values of Mw are used to estimate the seismic moment, M0, which is useful to constrain the upper limits for the amount of slip on the micro-fractures responsible for the microseismicity in individual stages. (3) A final discussion is included on the critical assumptions underlying a prior notion that microseismic monitoring would provide a poor characterization tool for the hydraulic fracturing process and the associated fracture network development – because only a minuscule fraction of the injection energy would be represented by the recorded microseismic energy. 1. Introduction The occurrence of abundant shear-slip and dilation of micro-fractures in the vicinity of a wellbore during hydraulic fracture treatment has been well-established by microseismic monitoring programs (Stegent and Candler, 2018). The release of elastic strain associated with local stress and pore pressure changes – induced by the hydraulic fracturing – is what causes the microseismic activity to occur in the so-called stimulated rock volume (SRV). Triangulation aims to locate the microseismic events to map out the overall extent of the microseismic cloud. A large portion of the recorded microseismic activity is caused by shear-slip of micro-fractures while opening of the hydraulic fractures also releases elastic energy waves (P and S) (Maxwell, 2011; Warpinski et al., 2012). Microseismic receivers, placed in multiple locations near the hydraulically fractured well, capture the seismic energy as the rock – strained by the hydraulic fracture treatment – releases elastic energy.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.90)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract In the past decades, most oil explotation in the White Tiger oil field was produced from the basement reservoir. However, in recent years, these pay zones consist of basement reservoirs, Oligocene reservoirs, and Miocene reservoirs of which oil field s have been declined in oil production rate due to several issues such as complex fracture network, high heterogeneity formation, high water cut, and the reduction of reservoir pressure. The huge issues in the most production wells at basement reservoir were high water cut and it has been significantly increasing during oil production yearly. Therefore, the total amount of oil production in all pay zones sharply decreased with time. At present, the lower Miocene reservoir is one of the best tight oil reservoirs to produce oil extractrion. The lower Miocene reservoir has been faced some issues such as high heterogeneity, complex structure, catastrophic clay swelling, low connectivity among the fractures, low effective wellbore radius and the reservoir that is hig h temperature up to 120°C, the closure pressure up to 6680psi, reservoir pressure up to 4500 psi, reservoir depth up to 3000m. Another reason low conductivity consists of both low reservoir porosity ranging from 1% of the hard shale to 10% of the sandstone formation, and the low permeability raining from 1md to 10md. By considering the various recovery methods, the integrated hydraulic fracturing stimulation is the best tool to successfully stimulate this reservoir, which method allows an increase in oil production rate. In the post fractured well has been shown an increase in productivity over 3 folds in comparison with the base case with fracture half-length nearly 75m, and fracture conductivity about 5400md.ft, which production rate is higher than the production rate of the base case. In addition, the proppant mass is used of 133,067 lbs of which the first main stage is to pump sinter lite bauxite proppant type of 20/40 into the fractures and the next big stage is to pump sintered ball bauxite proppant size of 16/30 into the fractures, which not only isolate proppant flow back but also increase fracture conductivity at the near wellbore as wel as high productivity rate after fractured well. To improve proppant transport, fract uring fluid systems consist of Guar polymer concentration of 11.2 pptg with these additives to form a total leak-off coefficient of 0.00227 ft/min.
- Asia > Vietnam > South China Sea (0.48)
- North America > United States > Colorado (0.46)
- North America > United States > Mississippi > Perry County (0.34)
- (2 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- North America > United States > Arizona > San Juan Basin (0.99)
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 9-2 (0.99)
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 09-1 > Bach Ho Field (0.99)
- (3 more...)
A fracture treatment, common where high fracture flow conductivity is needed. Very high pressures and very high proppant loadings are applied near the end of a fracture treatment where the tip of the fracture has stopped growing due to bridging of proppant at the fracture dip because of dehydration (frac fluid leakoff).
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Reducing the Placement Cost of a Pound of Proppant Delivered Downhole
Sochovka, Jon (Liberty Oilfield Services) | George, Kyle (Liberty Oilfield Services) | Melcher, Howard (Liberty Oilfield Services) | Mayerhofer, Mike (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services)
Abstract The shale industry has changed beyond recognition over the last decade and is once again in rapid transition. While we are unsure about the nature of innovations to make US shale ever more competitive, we are certain that the current downturn will drive a further reduction in $/BO – the total cost to lift a barrel of US shale oil to the surface. As a result of an increase in scale and industry efficiency gains, the all-in price charged by service companies to place a pound of proppant downhole has come down from more than $0.50/lb in 2012 to about $0.10/lb today. In this paper, we discuss what components have contributed to this reduction to date and use several case studies to illustrate the potential for further cost reductions. The authors used FracFocus data to study a variety of placement and production chemicals for about 100,000 horizontal wells in US liquid rich basins, including the Williston, Powder River, DJ, Permian basins, as well as SCOOP/STACK and Eagle Ford. All chemicals used were averaged on a per-well basis into a gallon-per-thousand gallons (gpt) metric. In the paper, we first provide an overview of trends by basin since 2010 for these chemical additives. Then, we perform Multi-Variate Analysis (MVA) to determine if groups of these chemicals show an impact on production performance in specific basins or formations. Finally, through integration of lab testing (on fluid systems and proppants), a liquid-rich shale production database and FracFocus tracking of industry trends, the authors developed a list of case histories that show modest to significant reductions in $/BO. In this paper we focus on proppant delivery cost – the cost to place a pound of proppant in a fracture downhole, where it can contribute to a well's production for years to come. The last decade saw a 10-fold increase in horsepower, a 20-fold increase in yearly stages pumped and a 40-fold yearly proppant mass increase. One result of this increase in scale, was a gain in efficiencies, which led to an average 3-fold fracturing cost decrease to place a pound of proppant downhole. We will document this trend in detail in the paper. A significant industry trend over the last decade has been a "viscosity for velocity" trade. The change to smaller mesh regional proppants, in combination with an increase in pump rates on frac jobs in the US, has allowed fluid systems to become more "watery". At the same time, the industry is moving from guar systems to polyacrylamide-based systems that exhibit higher apparent viscosities at low to ultra-low shear rates. These newer High Viscosity Friction Reducer (HVFR) systems show superior proppant carrying capacity over traditional slickwater fluid systems. Regained conductivity testing has shown that these HVFR systems are generally cleaner for fracture conductivity than guar systems. Along with changes to base chemistry, a 2- to 5-fold increase in disposal costs and an overall "green initiative" over the last decade have resulted in a push to maximize recycled water usage on these HVFR jobs. These waters can be in excess of 150,000 TDS (Total Dissolved Solids) which present challenges across the board when designing a compatible fluid system that fits the needs in terms of viscosity yield, scale inhibition and microbial mitigation etc. – all while keeping costs low. Specialty chemicals, such as Hydrochloric Acid (HCl) substitutes that have similar efficacy as HCl but significantly lower reactivity with human skin, have helped significantly to improve operational safety around previously-categorized hazardous chemicals, and have helped reduce cost and improve pump time efficiency. Measurement of bacterial activity during and after fracture treatments can help with the best economic selection of the appropriate biocide. These simple measurements can help further reduce what is spent on the necessary chemical package to effectively treat a well. This paper provides a holistic view of fluid selection issues and shows a real-data focused methodology to further support a leaner approach to hydraulic fracturing.
- Research Report (0.46)
- Overview (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.34)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (31 more...)
My older brother went to Texas A&M. I decided I wanted to follow in his footsteps, so I started out in electrical engineering, like my brother. But my dad was exploration manager for Lonestar Producing Company. During the summer after my freshman year, some of my dad's associates told me I should consider the oil business. I did as suggested and changed majors shortly thereafter.
- Asia (0.70)
- North America > United States > Texas (0.52)
- North America > United States (0.89)
- Europe (0.89)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (0.70)
- Management (0.70)
Authors JW Blaney, Andreas Michael, Michael Cronin, and Abhijeet Anand are members of the TWA Editorial Committee. Prospectus: At a macro-level, midstream congestion due to insufficient pipeline takeaway is limiting production and development potential in the Permian Basin. However, maintaining profitability and a social license to operate requires sensible management of oil, gas, and water. It is easy to forget that our industry produces many times more water--that must be treated, recycled, and/or disposed of--than hydrocarbon. Water oil ratios (WOR) between 2:1 and 15:1 are not uncommon, which has increased competition for space in saltwater disposal (SWD) injection wells.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.89)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
After graduating from the US Naval Academy in Annapolis, Maryland, I spent 6 years in the US Navy and decided to move on when my obligation was over. After finishing my MBA, I began to look for a job. With an Annapolis degree, 6 years of management experience, and an MBA, I had numerous job offers from a wide variety of companies. In 1981, the oil and gas business was in full swing and many firms were hiring. The process of searching for and producing oil and gas was fascinating, and it called on a lot of the skill sets that I had acquired in my career.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Military > Navy (0.89)
- Government > Regional Government > North America Government > United States Government (0.55)
- Reservoir Description and Dynamics (1.00)
- Management (0.68)
- Well Completion > Hydraulic Fracturing > Re-fracturing (0.51)