Information Processing and Trusted Computing 

Abstract: This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract Previous studies have shown that waterflood recovery is dependent on the composition of injection brine in clastic reservoirs 1 2 3 4 5 . Some researchers have also shown that oil recovery from carbonates is dependent on the ionic composition of the injection water 6 7 . These studies have however been generated at laboratory conditions which are not representative of the reservoir, and therefore it is uncertain whether these IOR benefits are applicable to actual reservoir waterflood oil recovery. A reservoir condition coreflood study was therefore performed on core from a North Sea carbonate field (Valhall) to determine whether the recovery benefits seen in reduced condition experiments, were also obtained from full reservoir condition tests, using live crude oil and brine. In these reservoir condition tests, two reservoir core plugs were selected from the same reservoir layer and were similar in reservoir properties so that comparisons could be drawn between the experiments. Samples were prepared to give initial water saturations which were uniformly distributed and volumetrically matched to the height above the oil water contact of the samples in the reservoirs. The initial water saturation composition was based upon the simulated formation brine composition of the field. The plugs were then aged in live crude oil to restore wettability. Imbibition capillary pressure tests were then performed at full reservoir conditions, with live oil and brine, using the semi dynamic method. The first experiment utilised a simulated formation water and the second test utilised a simulated sea water, respectively, as the displacing water. The resultant data showed that the sea water used in the capillary pressure test modified the wettability of the carbonate system, changing the wettability of the rock to a more water wet state. This was indicated by comparing the saturation change in the spontaneous imbibition phase of the test between simulated formation and sea waters. Background Some recent publications 6 7 show oil recovery in carbonates is increased by the addition of sulphate to the injection water. These tests describe corefloods which have generally been performed at ambient or reduced conditions using dead fluids and show that the addition of sulphate at concentrations that are present in sea water, modify the rock wettability to increased water wet behaviour. Imbibition capillary pressure characteristics are key to describing recovery characteristics in fractured carbonates as they control fracture matrix interactions as well as oil drainage from oil wet pore surfaces. Any wettability modification to a more water wet system will therefore be identifiable in the imbibition capillary pressure data. A study was therefore designed to compare recovery from a North Sea carbonate core sample using sulphate free formation simulated brine, with sea water, which contains sulphate. Description of the Equipment

Abstract: The Mississippian Barnett shale of the Fort Worth Basin is one of the most successfully developed shale gas plays in North America by applying multistage hydraulic fracturing stimulation techniques in horizontal wells The fracturing design involves pumping low viscosity fluid with low proppant concentrations at high pump rate, commonly known as “slick water fracturing” Direct laboratory measurement of both natural and induced fracture conductivity under realistic experimental conditions with the Barnett shale samples is needed for reliable well performance analysis and fracturing design optimization During the course of this study a series of static conductivity experiments was completed The goal was to measure the conductivity of propped and unpropped natural and induced fractures using a modified API conductivity cell at room temperature The cementing material present on the surface of the natural fractures was preserved during the initial unpropped conductivity tests and removed for subsequent propped fracture conductivity measurements The induced fractures were artificially created by breaking the shale rock along the bedding plane to account for the effect of the irregular fracture surface on conductivity Proppants of various sizes were manually placed between rough fracture surfaces at realistic concentrations The two sides of the induced fractures were cut in a way to represent either an aligned or a displaced fracture face with a 01 inch offset The effect of proppant partial monolayer was also studied by placing proppants at ultra-low concentration The results from the experiments show that unpropped induced fractures can provide a conductive path after removal of free particles and debris generated when cracking the rock The aligned induced fractures have conductivities one order of magnitude lower compared to displaced induced fractures when unpropped Poorly cemented natural fractures are effective flow paths Unpropped fracture conductivity depends strongly on the degree of shear displacement, the presence of free debris and particles during fracture generation, and the amount of cementing material removed The propped fracture conductivity is weakly dependent on fracture surface roughness at higher proppant concentrations because the proppant pack is the dominant contributor to fracture conductivity Moreover, propped fracture conductivity increases with larger proppant size and higher areal concentration in the testing range of this study Results also show that proppant partial monolayers cannot survive higher closure stress Therefore, proppant packs with multiple layers of proppant are more beneficial than a partial monolayer by maintaining the conductivity at elevated closure stresses

Abstract: This paper examines issues with forecasting and evaluating production from unconventional gas reservoirs, such as the Barnett Shale. How can reservoirs be commercial with matrix permeability measured not in milli-Darcy or even micro-Darcy (10-3 mD), but as low as 10-100 nano-Darcy (10-6 mD)?