Capillary pressure is a crucial step in reservoir properties definition and distribution during static and dynamic modelling. It is a key input into saturation height modelling (SHM) process, understanding the fluid distribution and into reservoir rock typing process. Capillary pressure models provide an insight into field dynamic for the identification of swept zones and provide another calibration besides the log calculated saturation. Capillary pressure curve tends to be more complex in carbonates in comparison to sandstone reservoirs because of post deposition processes that impact the rock flow properties, hence complex pore throat size distribution (uni-modal, bi-modal or tri-modal). Therefore, accurate determination of this property is the cornerstone in the reservoir characterization process.
Capillary pressure can be obtained using several experimental techniques, such as mercury injection (MICP), centrifuge (CF) and porous plate (PP). Each method has its own inherited advantages and disadvantages. The MICP method tends to be faster, cheaper and provides a full spectrum of pore throat size of a plug. Whereas, the PP method can be carried out at reservoir conditions with minimum required corrections.
In this paper, a detailed workflow for quality control capillary pressure is discussed. The workflow is sub-divided into three main parts: Instrumental and experimental level, core measurement level and logs level. Experimental level starts with proper designing the actual procedure of the capillary pressure experiment. Parameters such as pore volume, bulk volume and grain density are investigated at core measurement level. In geological-petrography montage, all petrography data; X-Ray Diffraction (XRD), Scanning Electron Microscope (SEM), thin section and computed tomography scan (CT) are used along with the capillary pressure curve for assessment. Comparing various methodologies of experimental technique carried out on twin plugs, if exist, are also investigated. The capillary pressure that passes the previous QC steps is used as input into saturation-point comparison as a logs level QC. The saturation calculated from capillary pressure is compared to log-derived water saturation eliminating any issues with porosity and permeability of the trims and provides insight to the uncertainty level in the model. As an additional step, the MICP measurements are fitted with bi-modal Gaussian basis functions with two practical benefits. First, the quality of this fitting is a useful indicator for the evaluation of pore structure complexity and the identification erroneous measurements. Second, the fitting parameters are useful inputs for geological interpretation, rock typing and SHM. This rapid and automated workflow is a useful tool for screening, processing and integration of large-scale capillary pressure data sets, a key step in integrated reservoir description, characterization and modelling.
Minh, Chanh Cao (Schlumberger) | Crary, Steve (Schlumberger) | Singer, Philip M. (Schlumberger) | Valori, Andrea (Schlumberger) | Bachman, Nate (Schlumberger) | Hursan, Gabor (Saudi Aramco) | Ma, Shouxiang (Saudi Aramco) | Belowi, Ali (Saudi Aramco) | Kraishan, Ghazi (Saudi Aramco)
Reservoir wettability is a critical parameter affecting hydrocarbon distribution within and recovery from reservoir rocks. The sensitivity of nuclear magnetic resonance (NMR) responses to rock wettability has been demonstrated in a number of publications. These publications suggest that wettability can be determined in the laboratory from NMR T2 relaxation measurements, obtained in cores after proper cleaning, re-saturation, and aging with reservoir fluids. Wettability changes may be noticed on logging measurements as a downward shift of the oil peak in the T2 spectrum from the bulk T2 response of live oils. The main practical obstacle in the T2 shift-based evaluation of wettability is the poor separation of oil and water peaks in the T2 spectrum. The bulk T2 of live oils must be measured and the core sample must be perfectly cleaned to quantify the NMR surface relaxation effect.
We demonstrate an improved method based on two-dimensional mapping of NMR diffusion vs. T2 with two principal advantages. First, the separation between the oil and water signals is greatly improved compared with the T2-based approach. Second, key properties such as tortuosity (represented by the Archie cementation exponent m) and effective surface relaxivity can be inferred from the two-dimensional NMR maps using restricted diffusion models. The wettability index and the rock relaxivity can then be estimated from the effective surface relaxivities. These results are based on a single-step NMR measurement on fresh-state (or “as received”) plugs cored with water-base muds containing no surfactants and that should be available days after the cores are recovered.
A wettability index using this new NMR method was obtained for carbonate samples from Middle East reservoirs. A strong correlation coefficient of R2 = 0.7 is observed between this new NMR approach and the standard, more time-consuming methods such as the U.S. Bureau of Mines technique. A sensitivity study of the NMR wettability index versus signal-to-noise ratio is performed on the core data, to assess the feasibility of this new technique down hole. The results suggest that it is possible to obtain reservoir wettability using downhole NMR measurements under appropriate conditions and provided sufficient signal-to-noise is obtained.
In complex and heterogeneous carbonate reservoirs, computing an accurate log derived water saturation (SW) where more than one pore type is present, poses a challenge for log analysts and geomodelers. Despite the application of a large number of log based techniques, log derived SW in these situations fails to compensate for the effects of microporosity because it does not accurately represent moveable hydrocarbon pore volume. Alternative techniques must be developed and implemented to reduce the uncertainty in hydrocarbon estimation and for use in dynamic simulation.
Failing to account for the affects of microporosity can have a major impact on hydrocarbon reserve estimation because the capillary bound water contained in the microporosity can cause SW estimates using conventional open hole logs to be inaccurate and this can lead to inaccurate estimation of moveable hydrocarbons. Such errors lead to the possibility that some potentially productive intervals could be bypassed or confused as water productive, when in fact they produce dry oil in production tests. Furthermore, substantial errors in calculation of Original Oil in Place (OOIP) can also be made. We present the results of core based saturation height modeling for the Uwainat Member which has been applied to compensate for the dynamic effects of microporosity in simulation.
The Uwainat Member is the main Mid-Jurassic carbonate reservoir in Bul Hanine (BH) Field, offshore Qatar. The Uwainat Member has an oil rim with an API gravity of approximately 37°, and fairly dry gas cap. The oil rim is about 140 ft thick and the gas cap column is approximately 260 ft. The oil saturation pressure at the Gas-Oil-Contact (GOC) is 4367 psia. Gas cap expansion provides the main energy for the reservoir flow.
The Uwainat Member consists of a variety of carbonate rock types which are characterized by the occurrence of various pore types and complex pore geometry with varying proportions of microporosity. Complex pore size distributions encountered in carbonate rocks have a large impact on the fluid flow characteristics of reservoirs. Pervasive internal microporosity associated with micrite in packstone, wackestone, mudstone and even composite grainstone lithofacies affects the petrophysical properties of these rocks and challenges conventional modeling techniques. The presence of microporosity suppresses the resistivity response of induction and laterolog logging tools, leading to a low contrast in resistivity between water saturated and oil saturated rocks. Quantification of microporosity is critical in these lithotypes, to understand capillary behavior and why they appear to have such thick transition zones. In reservoirs such as the Uwainat at BH, primary drainage processes preferentially displace brine from pore network paths with the largest pore throat radii at the lowest elevations above the free water level (FWL). Microporosity remains brine saturated until much higher capillary pressures are reached.
Internal micropores occur within fine grained particles which have high internal surface area. In microporosity, high surface area and the small pore size ensure that micropores remain water-wet at low capillary pressures. By contrast, the larger pores (macropores) are more susceptible to wettability alteration and can become oil-wet. In addition, drainage capillary pressure curves for rocks with a high proportion of microporosity tend to suggest or give the impression of a thick transition zone. This kind of apparent transition zone can be modeled by superposition of the capillary trends of two porosity systems, a micro and a macro system. Modeling the capillary pressure system in this way helps to explain the dynamic flow behavior of dry oil production in some of the Mid-Jurassic Uwainat intervals which have very low measured e-log resistivity (~ 1 ohm.m), and high apparent SW.