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This paper reviews the relative advantages and disadvantages of the following methods for measuring the remaining oil saturation (ROS): pressure coring, sponge coring, the single-well tracer method, and PNC, C/O, electric, EPT and NML logging methods. Careful planning and execution by well-trained personnel is considered mandatory for the field application of these methods.
This paper reviews the relative advantages and disadvantages of the following methods for measuring the remaining oil saturation (ROS): pressure coring, sponge coring, the single-well tracer method, and PNC, C/O, electric, EPT and NML logging methods. Careful planning and execution by well-trained personnel is considered mandatory for the field application of these methods.
The North American hydrocarbon supply market has been transformed by recent discoveries in regionally continuous reservoir units consisting of shale and tight sands. Effective porosity values in these reservoirs average as low as 2% to 6% with nanoDarcy permeability in situ. Classical means of determining resource-in-place values in these unconventional formations involves integrating core and log analysis methodologies, where numerous levels of uncertainty exist. Controlled pressure coring operations were conducted on a sequence of wells drilled into various maturity windows in the rapidly emerging liquids-rich Duvernay Shale through the course of 2011 and 2012. Capturing critical resource-in-place parameters and conducting quantitative analysis of volatile hydrocarbons contained within the cored interval required the development of new field and laboratory methodologies. These procedures represent the only currently available workflow capable of directly capturing and analyzing reservoir hydrocarbons from core material. Field operations and core preservation steps were developed to maintain the integrity of the hydrocarbon system during shipping and core processing. Additionally, a laboratory methodology was developed for preserving and extracting liquid hydrocarbons from core material. By quantitatively recombining these extracted fluids with volatile hydrocarbons captured from the controlled pressure coring operation, in situ PVT behavior of this single-phase volatile oil/condensate reservoir can be determined. As a result, recombined fluids can be compared to production samples for the purpose of studing pore scale mechanisms affecting production. Key breakthroughs were made during all stages of the workflow, and it was determined that core capture and surface handling operations are just as important as developing the new laboratory techniques required to understand resource uncertainty, effective fluid mobility, and PVT behavior. This paper describes and documents the key advancements made in coring operations and specialized core analysis, as well as their role in accurate quantification of hydrocarbons in place and the determination of in situ PVT behavior of the Duvernay Shale.
Summary A combination of advanced Polycrystalline Diamond Compact (PDC) core bit technology and modified coring techniques has produced waterbase mud cores of high permeability sandstone with no mud filtrate invasion over two-thirds of the core's cross-section. Waterbase mud filtrate invasion while coring detrimentally affects water saturation and its distribution, residual oil saturation, and rock wettability which are used to calculate total reserves, movable oil, etc. Multimillion dollar decisions are based on these parameters which have a limited reliability due in part to mud filtrate invasion. This coring technique will eliminate mud filtrate invasion as a factor in these measurements. The majority of filtrate entering the core is generated by dynamic fluid loss from gage cutters in and near the throat of the core bit. Core invasion can be minimized by increased coring rate, reduced filtration area, increased bridging solids in the mud, and reduced contact time with gage cutters. This has been achieved by:reducing the number of cutters over the entire bit (increases depth of cut which can increase penetration rate);using a parabolic bit design (reduces the dynamic filtration area);using a low fluid loss mud (increases bridging solids);reducing the number of gage cutters (reduces contact time of gage cutters) andeliminating all throat diamonds (leaves mud cake intact). These bit design criteria are supported by laboratory coring tests and analysis. Three versions of these improved core bits have been tested in full scale laboratory coring operations. Bromide tracers have been used to evaluate the amount of mud filtrate contamination. These tests indicate invasion of filtrate can be limited to the outer three fourths of an inch (1.905 cm) of a four inch (1 0. 1 6 cm) diameter waterbase core at coring rates greater than 90 ft/hr (27.6 M/hr). The limited core invasion seen here is interpreted with a simple model incorporating the mechanisms of spurt-loss from PDC cutters in contact with the core and static filtration above that point. point. The conclusions reached from laboratory core invasion have been verified in field tests by coring sandstone oil reservoirs containing connate water saturation. This coring method has provided reservoir rock having in-situ rock wettability and water saturations unaffected by filtrate invasion. Introduction Filtrate invasion while coring has been a major factor affecting the validity of fluid saturations and laboratory measurements such as wettability and relative permeability. When pressure coring to measure oil saturation, tracers are often used to evaluate invasion. Filtrate invasion will decrease high initial oil saturations and in the most severe cases may even mobilize residual oil saturation. These effects may be minimized by increasing core diameter and formulating drilling muds with low spurt loss. High coring rate and decreased overbalance between the mud and the formation have also been identified as beneficial in minimizing mud filtrate invasion. Numerous studies document the effect of drilling mud components on rock wettability. Considerable effort is devoted to the measurement of relative permeability, both water-oil and gas-oil, in the laboratories of most major permeability, both water-oil and gas-oil, in the laboratories of most major oil companies and by commercial laboratories. These data are used in numerical simulations of field performance under various depletion scenarios. These performance predictions are used to make multimillion dollar investment decisions. Most laboratories attempt to preserve in-situ wettability by use of special coring fluids and by preserving the core at the wellsite to minimize further changes in wettability. Some laboratories go to considerable effort to make all water-oil relative permeability measurements at reservoir conditions on core having, as nearly as possible, the in-situ wettability. The reliability of relative permeabilities measured on so called ‘native wettability’ core samples must always be qualified because mud filtrate invasion usually modifies the water saturation and its distribution and may modify wettability. In mixed wettability rock (as defined by Salathiel), there is reason to question whether the original connate water saturation and distribution can be restored so that a primary imbibition water-oil relative permeability can be obtained. These uncertainties, in part, have caused a great diversity of opinion within the oil industry on how to measure water-oil relative permeability. Considerable improvement in data reliability could be achieved if coring mud filtrate invasion is eliminated as an issue. Invasion when coring occurs by three mechanisms as shown in Figure 1. First, core invasion may occur ahead of the bit. A filtrate bank builds up at low coring rates. Analysis of laboratory data in this paper indicates the interplay of filtrate interstitial velocity in the rock and core bit velocity through the rock control filtrate bank formation. Second, core invasion occurs at the core bit. Filtrate is generated at high rates due to bit cutting action.
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