TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn a large clastic reservoir of Saudi Arabia, rock typing by rock-quality-index (RQI) and flow-zone-indicator (FZI) proved to be an effective technique to develop porositypermeability transforms for 8 lithologic facies in a reservoir model. Moreover, capillary pressure and relative permeability curves could be grouped into defined rock types as well. This technique provided an effective tool to distribute permeability, initial water saturation, relative permeability, and residual oil saturation per lithologic facie. This paper presents through a case study the methodology applied for generating permeability and water saturation distribution by lithologic facies and hydraulic units and its impact on simulation history match and future prediction.
Reactive mud cake breaker fluids in long open hole horizontal wells located across high permeability sandstone reservoirs has had limited success because they often induce massive fluid losses. The fluid losses are controlled with special pills, polymers and brine or water, causing well impairment that is difficult to remove when oil-based mud (OBM) drill-in fluids (DIFs) are used. This situation has resulted in the drive for an alternative cleanup fluid system that is focused on preventing excessive fluid leak off, maximizing the OBM displacement efficiency and allowing partial dispersion of the mud cake for ease of its removal during initial well production. The two-stage spacer application is composed of a nonreactive fluid system, which includes a viscous pill with nonionic surfactants, gel pill, completion brine and a solvent.Extensive laboratory evaluation was conducted at simulated reservoir conditions to evaluate the effectiveness of the OBM displacement fluid system. The study included dynamic high-pressure/high temperature (HP/HT) filter press tests and coreflood tests in addition to wettability alteration, interfacial tension and fluid compatibility tests.The spacer fluid parameters were optimized based on wellbore fluid hydraulic simulation and laboratory test results, which indicated minimal fluid leak off and a low risk of emulsion formation damage. Three well trials were conducted in a major offshore field sandstone reservoir drilled with OBM. All three trial wells (one single and two dual laterals), which were treated, have demonstrated improvement in production performance. This paper will discuss in detail the spacer fluids optimization process, laboratory work conducted and the successful field treatments performed.
Increases in well complexity and stimulation challenges have led to more complicated stimulations. The challenge that consistently arises after conceptually designing the treatment is how to determine the zonal coverage and evaluate the stimulation, especially in extended reach wells in carbonate reservoirs. Significant effort has been spent on using modern technologies to qualitatively evaluate zonal coverage and estimate the skin factor evolvement after the treatment. No work has yet answered the following question: How does matrix acidizing alter near-wellbore permeability and affect the zonation of the wellbore when treating carbonate reservoirs?In long horizontal wells that are drilled in carbonate formations, it is believed that wormholing significantly alters the near-wellbore apparent permeability. Nevertheless, methods to estimate the change in permeability resulting from a matrix treatment are not known, and usually the change is accounted for in simulators by assigning a very low skin value. Other work conducted in carbonate reservoirs using pressure transient analysis (PTA) techniques has shown that applying a change in permeability is necessary to obtain a type-curve match.This paper presents an innovative workflow and algorithm to estimate the changes in the critical matrix rock properties and how to incorporate these changes into further simulation. The algorithm integrates the while drilling mobility data, open hole porosity logs, pressure transient data, distributed temperature survey data, and production logging data to verify the accuracy of the model by using the flow rate as the control parameter for iterations.A case study shows how we could derive a flow profile for the pre-stimulation stage, optimize matrix stimulation treatments in real time according to the formation response and diversion efficiency, define reservoir zones that are contributing to flow before and after the treatment, and finally, estimate new values of permeability and skin to be utilized in post-treatment reservoir simulations.
Achieving effective cleanup while flowing back the well after drilling is key for maximizing productivity and minimizing near wellbore damage. This paper discusses the best practices for cleanup in a sandstone reservoir drilled with oil-based mud (OBM), and installed with inflow control device (ICD) completions. The findings are based on the evaluation of different cleanup methods: coiled-tubing deployed nitrogen kickoff, chemical treatments, artificial lift-electric submersible pump vs. natural flow, time spent on cleanup, and flow rate. Applications include sand control completions run in open hole with ICDs over long horizontal sections. Resultsshow that in relatively high darcy sands, using proper chemical treatments and spending more time for flow back with higher rates will maximize productivity and minimize near wellbore damage. Choosing the correct and effective cleanup method will minimize near wellbore skin, maximize productivity, effectively drain the reservoir and save intervention costs for cleanup.
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