Shell Development Co.; and S.K. Hara," Shell Offshore Inc. q SPE Members Copyright1995, Sodety of PetroleumEngineers,Inc. Thw paper wea preperedfor presentationat the Western RegionalMeethg held in Bakersfield,CA, U.S.A., S-10 March 1SS5. Th@PSPWwss selaotedfor preeentatbnby an SPE ProgramOommittaefolfowingreviewof informationcontainedIn an abatrsoleubmittadby the authef(s).Contentsof the paper, es presented,have not bean reviewedby the Sooiity of PetroleumEngineersand era sub@t to oormotionby the author(s).The material,se pWSSntW$ dOSenOtn--lY re~of enY~tl~Ofthe -kfy of PStdeUM Engineers,its officers,or members.Paperspresentedat SPE meetingsare aubjeotto publication ravkw by EditorialCommHtees of the .%cIefy of Pafm$aum Engineers. Permission toqy !srestricted toan stmtrect ofnotmorethan300 words.Illustmfiona mayI-Wb oapiad.The sbatrsct shouldcontainconapicucua acknowkdgmant of where end by whomthe pspar is presented.Write Librarian,SPE, P.0, Sox SSSS3S, Rkhardaon, TX 750s3-SS3S,U.S.A., Telex 1SS24.5SPEUT. ABSTRACTWithdrawal of fluids from shallow, thick and low strength rock can cause substantial reservoir compaction leading to surface subsidence and wel! failure. This is the case for the Diatomite reservoir, where over 10 ft of subsidence have occurred in some areas. Well failure rates have averaged over 3°/0 per year, resulting in several million dollars per year in well replacement and repair costs in the South Belridge Diatomite alone. A program has been underway to address this issue, including experimental, modeling and field monitoring work. An updated elastoplastic rock law based on laboratory data has been generated which includes not only standard shear failure mechanisms but also irreversible pore collapse occurring at low effective stresses (< 150 psi). This law was incorporated into a commercial finite element geomechanics simulator. Since the late 1980s, a network of level survey monuments has been used to monitor subsidence at Belridge. Model predictions of subsidence in Section 33 compare very well with field measured data, which show that water injection reduces subsidence from 7-8 inches per year to 1-2 inches per year, but does not abate well failure.The model has been used to infer potential well failure mechanisms resulting from fluid withdrawal policies and to estimate the impact of alternative operating policies for a 5/8-acre waterflood project; results show that aggressive operation of a newly completed producer can potentially damage a nearby well and that 1/1 producer/injector ratio results in significantly less subsidence and lower shear strains than a 3/1 ratio.

Editor's note: This is the sixth in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. White papers covering these challenges are available at www.spe.org/industry/ globalchallenges and allow reader comments and open discussion of the topics.

Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in two different horizontal cold-producing heavy oil wells in Alberta is presented. The first field case study discusses the application of electric heating in a mature, depleted field as a secondary recovery method while the second case study examines a virgin heavy oil reservoir, where cold production by artificial lift was economically challenged. The completion, installation, expected and actual results of both cases studies are compared and contrasted. Both field deployments demonstrate the benefits and efficacy of applying downhole electric heating. In the case of the mature depleted field, electric heating resulted in a 4X-5X increase in oil rate, sustained over a period of close to two years. The energy ratio of the heating value of the incremental produced oil to the injected heat was slightly over 7.0. In the virgin heavy oil field, electric heating reduced the viscosity of the oil in the wellbore from time zero, which allows for higher rates of oil production along the complete length of the long horizontal lateral at higher, if desired, bottomhole pressures than in a cold-producing well. This degree of freedom may ultimately allow for an operating policy that suppresses excessive production of dissolved gas, thereby helping conserve reservoir energy. Early production data in this field show 4X-6X higher oil rates form the heated well than from the cold-producing benchmark well in the same reservoir. Numerical simulation models, which include reactions that account for the foamy nature of the produced oil and the downhole injection of heat, have been developed and calibrated against field data. The models can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method, which is crucially important in the current low oil price scenario. The same models can also be used during the execution of the project to explore optimal operating conditions and operating procedures. Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs in Alberta as well as around the world.

Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high-powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in a horizontal cold-producing heavy oil well in Alberta, Canada is presented in this paper. The field case demonstrates the benefits and efficacy of applying downhole electric heating, especially if it is applied early in the production life of the well. Early production data showed 4X-6X higher oil rates from the heated well than from a cold-producing benchmark well in the same reservoir. In fact, after a few weeks of operation, it was no longer possible to operate the benchmark well in pure cold-production mode as it watered out, whereas the heated well has been producing for twenty (20) months without any increase in water rate. The energy ratio, defined as the heating value of the incremental produced oil to the injected heat, is over 20.0, resulting in a carbon-dioxide footprint of less than 40 kgCO2/bbl, which is lower than the greenhouse gas intensity of the average crude oil consumed in the US. A numerical simulation model that includes reactions that account for the foamy nature of the produced oil and the downhole injection of heat, has been developed and calibrated against field data.  The model can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method. The same model can also be used during the execution of the project to explore optimal operating conditions and operating procedures. Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs around the world.

Summary The classic plots of dimensionless fracture conductivity (CfD) vs. equivalent wellbore radius or equivalent negative skin are useful for evaluating the performance of hydraulic fractures (HFs) in vertical wells targeting conventional reservoirs (Prats 1961; Cinco-Ley and Samaniego-V. 1981). The increase in well productivity after hydraulic stimulation can be estimated from the “after fracturing” effective wellbore radius or from the “after fracturing” equivalent negative skin. However, this earlier work does not apply to the case of horizontal wells with multiple fractures. A revision of the diagnostic plots is needed to account for the combination of the resulting radial-flow regime and the transient effect in unconventional reservoirs with ultralow permeability. This paper reviews and extends this earlier work with the objective of making it applicable in the case of horizontal wells with multiple fractures. It also demonstrates practical application of this new technique for fracture-design optimization for horizontal wells. The influence of finite fracture conductivity (FC) on the HF flow efficiency is evaluated through analytical models, and it is confirmed by a 3D transient numerical-reservoir simulation. This work demonstrates that a redefined dimensionless fracture conductivity for horizontal wells CfD,h = 4 is found to be optimal by use of the maximum of log-normal derivative (subject to economics) for HFs in horizontal wells, and this value of CfD,h can provide 50% of the fracture-flow efficiency and 90% of the estimated ultimate recovery (EUR) that would have been obtained from an infinitely conductive fracture for the same production period. This new master plot can provide guidance for hydraulic-fracturing design and its optimization for hydrocarbon recovery in unconventional reservoirs through hydraulic fracturing in horizontal wells.