Simulation of Thermally Induced Waterflood Fracturing in Prudhoe Bay

Abstract

Simulation of Thermally Induced Waterflood Fracturing in Prudhoe Bay A.M. Garon; A.M. Garon Standard Oil Production Co. Search for other works by this author on: This Site Google Scholar C.Y. Lin; C.Y. Lin Standard Oil Production Co. Search for other works by this author on: This Site Google Scholar V.A. Dunayevsky V.A. Dunayevsky Standard Oil Production Co. Search for other works by this author on: This Site Google Scholar Paper presented at the SPE California Regional Meeting, Long Beach, California, March 1988. Paper Number: SPE-17417-MS https://doi.org/10.2118/17417-MS Published: March 23 1988 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Garon, A.M., Lin, C.Y., and V.A. Dunayevsky. "Simulation of Thermally Induced Waterflood Fracturing in Prudhoe Bay." Paper presented at the SPE California Regional Meeting, Long Beach, California, March 1988. doi: https://doi.org/10.2118/17417-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Western Regional Meeting Search Advanced Search AbstractWaterflooding operations in the Prudhoe Bay field result in temperature reductions of up to 130F within the flooded region. As a result, the fracture gradient is significantly reduced, and the injection pressures may have to be reduced to avoid formation parting. The phenomena of fracturing resulting from thermally induced stress reduction was investigated to provide guidance for decisions on waterflood operating strategy.Thermal reservoir simulation was performed to determine the in-situ temperature and pressure distributions following various periods of water injection. A finite-element stress-analysis model was developed to calculate the changes in in-situ stress field. A three-dimensional fracture simulator was used to predict fracture growth and shape based on the calculated stress distribution. A thermal reservoir simulator was modified to include a simplified fracture mechanism and calibrated against step-rate test data. Fracture areas were then predicted with the modified reservoir simulator and correlated with the fracture shapes obtained with the fracture model.The fracture predictions confirmed field data which indicated that fractures created during well testing were short and confined to within the perforation interval. In addition, fractures created with clean water injection at pressures above the reduced fracture gradient were predicted to reach equilibrium lengths of less than about 200 ft.IntroductionThe Prudhoe Bay Oil Field on the Alaskan North Slope is the largest producing oil field in North America with over 21 Billion STB oil originally in place. The Sadlerochit sand body, of which the Ivishak sandstone is the main oil-bearing formation, is at a depth of about 9000 ft. The rock quality is generally high with permeabilities in the range from 100 md to 5 darcies. Water is currently being injected to promote oil production in portions of the reservoir. The waterflooding is being performed using variations of inverted nine-spot patterns with interwell distances of about 1500 ft.Injection water for the Prudhoe Bay waterflood Is obtained from two sources. Beaufort seawater is currently the primary source. The seawater is heated to 80F at the wellhead. Produced water, which is at about 150F, will eventually become the dominant source. As a result of this relatively cold water injection, the reservoir is significantly cooled from its initial temperature of 180 to 220F. Reductions in reservoir temperature range from 70 to 130 'F depending on the temperature and rate of water injection and the initial reservoir conditions.Changes In the reservoir temperature and pore pressure fields resulting from cold water injection can cause changes in the in-situ stress levels. Decreasing the reservoir temperature results in a reduction of compressive stress, while increasing pore pressure increases in-situ stress. For Prudhoe Bay conditions, the temperature effect is dominant, and waterflooding can significantly reduce in-situ compressive stress levels. As a consequence, the fracture gradients will be reduced from their original values.Prior to waterflooding, formation breakdown was generally observed to occur at injection gradients of 0.60 to 0.70 psi/ft, and the maximum injection guideline used by the Prudhoe Bay operators was 0.60 psi/ft. After waterflood startup, formation breakdown gradients were determined by step-rate tests to be as low as 0.50 psi/ft.P. 193^ Keywords: enhanced recovery, fracture growth, injection, reservoir simulator, injection pressure, upstream oil & gas, fracture, wellbore, gradient, perforated interval Subjects: Hydraulic Fracturing, Improved and Enhanced Recovery, Waterflooding This content is only available via PDF. 1988. Society of Petroleum Engineers You can access this article if you purchase or spend a download.