Thus far, an indirect generalized method to predict pore pressure under subpressured conditions has not been reported in the literature. In this work, an innovative procedure is presented for estimation of pore pressure and optimization of wells drilled in the abnormally subpressured Deep Basin of the Western Canada Sedimentary Basin (WCSB). The procedure starts with detailed evaluation of five wells drilled in a township that covers the study area. Pore pressure was calculated from sonic logs and the modified D exponent by the use of Eaton's method (Eaton 1975), which proved to be the most effective approach for abnormally subpressured conditions over a variety of methods tested (Contreras et al. 2011). The optimization procedure was carried out by use of the apparent-rock-strength log (ARSL), which is an effective indicator of formation drillability and is very sensitive to the pore pressure. Next, optimization of individual sections in each well was carried out to determine the optimum types of bits and operational parameters for the lowest cost of drilling. An artificial-intelligence function was implemented to set up the optimum combination of parameters in such a way that the rate of penetration (ROP) (m/h) was increased after a number of simulation runs while controlling the bit wear. Special attention was focused on tight gas reservoirs for selection of the most suitable parameters that increase the quality of drill cuttings. It was concluded that the roller-cone bit IADC 547 (with at least 0.73 hp in the bit per square inch) provides the best-quality cuttings for the Nikanassin Group. This is of paramount importance for increasing accuracy in the quantitative determination of permeability and porosity from cuttings particularly in those tight gas reservoirs where the amount of cores is very limited. It is concluded that wells in the Deep Basin of the WCSB can be drilled efficiently with seven bit runs while maintaining the cuttings quality, bit-wear level, and well stability at a significantly high average ROP of 13 m/h. Another conclusion is that the normal trend methods from sonic logs are the most effective approach when dealing with an abnormally subpressured basin.
The amount of tight formations petrophysical work conducted at present in horizontal wells and the examples available in the literature are limited to only those wells that have complete data sets. This is very important. But the reality is that in the vast majority of horizontal wells the data required for detailed analyses are quite scarce.
To try to alleviate this problem, a new method is presented for complete petrophysical evaluation based on information that can be extracted from drill cuttings in the absence of well logs. The cuttings data include porosity and permeability. The gamma ray (GR) and any other logs, if available, can help support the interpretation. However, the methodology is built strictly on data extracted from cuttings and can be used for horizontal, slanted and vertical wells. The method is illustrated with the use of a tight gas formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). However, it also has direct application in the case of liquids.
The method is shown to be a powerful petrophysical tool as it allows quantitative evaluation of water saturation, pore throat aperture, capillary pressure, flow units, porosity (or cementation) exponent m, true formation resistivity, distance to a water table (if present), and to distinguish the contributions from viscous and diffusion-like flow in tight gas formations. The method further allows the construction of Pickett plots without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of many tight formations currently under exploitation.
It is concluded that drill cuttings are a powerful direct source of information that allows complete and practical evaluation of tight reservoirs where well logs are scarce. The uniqueness and practicality of this quantitative procedure is that it starts from only laboratory analysis of drill cuttings, something that has not been done in the past.
This work establishes an effective approach to predict pore pressure in the overpressured Montney Shale and overburden from sonic logs by implementing normal-trend and explicit methods. The cause of the overpressure condition in the Montney is also addressed. These two methods were selected on the basis of the study carried out by Contreras et al. (2011) that worked successfully for pore pressure prediction under subpressured conditions in parts of the Western Canada Sedimentary Basin (WCSB). As a second objective, the stress faulting regime was determined in the study area by using Stress Polygons and data from diagnostic fracture injection test analysis as a quantification of the minimum horizontal stress. This is of paramount importance since there is not a generic theory about the stress faulting regime for most of the west region of the WCSB.
The Eaton method from sonic logs (Eaton, 1975) and the Bowers method (Bowers, 1995) were implemented in two vertical wells drilled through the Montney shale. The first part of the analysis considered two normal compaction trends but unreasonable pressure profiles were obtained and required a revision on the depositional environment. It was found that for the study area three normal compactions trends have to be considered. The Bowers method was initially implemented using both loading and unloading conditions in order to establish a safe range of pore pressure to allow successful well plans.
It is concluded that undercompaction could be masked as the only overpressure mechanism in the Montney shale in the study area. The formation experiences an inverse faulting regime that will lead to the creation of horizontal hydraulic fractures. The Eaton method using three normal compaction trends and an exponent equal to 0.9 works successfully in the study area. The Bowers method using the loading and the unloading conditions, and the specific correlation parameters were found to be suitable for the study area and can be extrapolated to adjacent future production and exploratory wells.
A basin centered gas accumulation (BCGA) is a "continuous petroleum accumulation?? characterized by low permeability, the absence of downdip water, the absence of obvious traps and seals, the presence of pervasive gas or oil saturation over very large areas, abnormal pressures (either high or low), and the relative proximity to source rocks. The question is if it is reasonable to think that gas can be trapped over millions of years by an updip water block.
A reservoir simulation model has been created in order to answer this question. The water seal is shown to be the result of very low permeability and high capillary pressures, properties that are generally found in tight gas formations. The model is defined by a geometry that mimics the geologic interpretation of the Nikanassin BCGA in the Western Canada Sedimentary Basin (WCSB) and rock properties that provide a good representation of the real behavior of the reservoir in the Deep Basin. Different models were created trying to understand sensitivities to permeability and capillary pressure in the distribution of downdip gas and updip water over thousands of years. The results obtained appear consistent and reliable when compared with factual information from the Deep Basin.
The conclusion is reached that updip water blocks provide good seals in the Deep Basin. The simulation also confirms that special completion and stimulation practices are required in order to produce gas at economic rates from tight gas reservoirs.
The qualifier "unconventional?? for tight gas reservoirs is certainly valid. The lack of water leg, the seal provided by a "water block?? updip the gas reservoir, the porosity associates with slots and dissolution secondary pores, the abnormal pressure (high or low with respect to a normally pressured reservoir) and the very large continuous areas where they are found make them certainly "unconventional??. We present the terminology associated with these types of reservoirs next.
Basin Centered Gas Continuous Accumulation
Basin centered gas accumulations, tight gas formations; coalbed methane, oil and gas shales, and gas hydrates are generally categorized as "continuous petroleum accumulations??. Those continuous accumulations have two key geologic features in common: first, they consist of very large areas with pervasive oil or gas saturation, and second they do not depend upon the buoyancy of oil or gas in water for their existence. Petroleum as defined by the United States Geological Survey is the sum of oil, natural gas and natural gas liquids.
In addition to the key features mentioned above, there are other important characteristics of continuous accumulations including the lack of down dip water, absence of obvious trap and seal, large areal extent, low matrix permeability, abnormal pressure (either high or low), and close proximity to source rocks.
Solano, Nisael A. (University of Calgary) | Clarkson, Christopher R. (University of Calgary) | Krause, Federico (University of Calgary) | Lenormand, Roland (CYDAREX) | Barclay, Jim E. (ConocoPhillips) | Aguilera, Roberto (University of Calgary)
Estimation of rock properties from drill cuttings is proving valuable in the geologic description of tight gas strata. The characterization scheme includes an integrated analysis of detrital and authigenic mineralogy, pore geometry, and flow and storage capacity using drill cuttings samples calibrated with a limited amount of core data. This methodology has been successfully applied to characterize the fine-grained siliciclastic, shallow marine Nikanassin Formation in the Deep Basin of Alberta.
This workflow is particularly useful for the characterization of undercored low permeability hydrocarbon-bearing intervals from both new and legacy wells. Macroscopic description of drill cuttings samples, coupled with petrographic analysis performed on custom made multi-sample thin sections from the same samples allows a direct correlation between these two observations. The principal detrital and authigenic components are also investigated through microprobe analysis and SEM imaging of selected samples. Porosity values and dominant pore geometries are estimated using laboratory measurements and thin section image analysis. Finally, permeability values are measured using the Liquid Pressure Pulse methodology on drill cutting samples.
Porosity and permeability of the analyzed samples ranges between 2-13%, and 0.01-0.25 mD, respectively. Porosity values from drill cuttings samples are found to be slightly higher than routine core analysis measurements, which in turn usually have higher values than porosity estimated from thin sections. A high degree of reproducibility was confirmed for the porosity values obtained from the saturation method on drill cutting-sized samples, with resultant values comparing very well with measurements from standard nuclear magnetic resonance on the same samples. Reservoir quality within the analyzed samples is highly affected by quartz overgrowth and subsequent carbonate cement, with the former increasing with depth. Compared to the dominant microporosity domain, remnant intergranular porosity significantly enhances the permeability of the samples.
This workflow represents an inexpensive yet comprehensive interpretation tool specially targeted to improve the geological understanding of potential by-passed tight gas formations, which usually lack representative cored intervals. In addition, economic returns can be highly optimized by partial replacement of coring programs by appropriate sampling and preservation of drill cuttings samples in new wells.
Shale and tight formations have long been a challenge for petrophysical interpretation. In the case of shales, the presence of clays and organic matter, complex mineralogy and pore structure make the log responses complicated. In tight reservoirs, the presence of connected and non-connected dissolution pores, microfractures and slot porosity also complicates the interpretations. This work seeks to integrate and digitize new petrophysical techniques and procedures that address these problems into a software system to assist with shale and tight reservoirs characterization.
A petrophysics software system that includes dual and triple porosity models as well as elastic geomechanical properties has been developed to assist with the evaluation of shale and tight formations. Some critical petrophysical parameters can be quantified, such as matrix, fracture, non-connected and effective porosities, water saturation, total organic carbon, level of organic metamorphism, flow regimes (continuous vs. diffusion-like) at any pressure of interest, as well as Young modulus, Poisson's ratio and minimum horizontal stress. Based on these estimates, detailed shale and tight reservoirs characteristics can be analyzed and the original hydrocarbons in place can be determined with good accuracy.
Practical workflows for calculating each parameter are also organized and integrated. Object-oriented programming techniques are utilized for the development of this software considering its development life cycle for large-scale software development. Optimization capacity adopted in the current development for the reuse of the software components for future development is also explained.
Two case studies using data from the Nikanassin formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB) and the Haynesville shale formation in Texas are presented to illustrate the software development and the application of the software. Conventional well log data, such as gamma ray, density, neutron, acoustic, resistivity, and cores and drill cuttings are utilized in the examples, which is further validated with other sources of information.
It is concluded that the methodology developed in this software will prove valuable and facilitate the petrophysical evaluation of shale and tight formations.
Electromagnetic mixing rules of the type developed by Maxwell Garnett, Bruggeman, and the Coherent Potential formula are shown to be useful for evaluation of the porosity (or cementation) exponent, m, in naturally fractured reservoirs represented
by dual and triple porosity models. Comparisons are made with core data from limestone, dolomite and tight gas reservoirs to corroborate results from the theoretical models.
Rigorous values of m reduce the uncertainty in calculated values of water saturation and hence improve estimates of hydrocarbons-in-place and recoveries particularly in situations where sufficient data are not available to utilize the material
The main advantage of the new method developed in this paper for petrophysical analysis is that it can handle with the use of one single equation the individual mixing rules mentioned above, and at the same time quantify values of matrix, fracture and non- connected vug porosity, and the cementation exponent of the total porosity system.
It is concluded that electromagnetic mixing rules provide a useful methodology for petrophysical evaluation of complex dual and triple porosity reservoirs.
Due to quick development in horizontal drilling and fracturing technologies, shale gas, formerly considered very difficult if not impossible to recover, has become one of the hottest energy topics. As a significant number of studies focus on fracture stimulation, drilling and completion optimization, only a limited number of studies have been carried out aiming at the investigation of shale structure at nanometer scale due to limited access to scanning electron microscopy (SEM), transmission electron microscopy (TEM) and atomic force microscopy (AFM), and also due to less experience using these instruments in studies of formation rocks.
SEM and TEM are all capable of revealing nano-scale structures of rock samples. AFM also offers some possibilities. In order to obtain images of high quality and ultra-high magnification, sample preparation is the initial and probably most important step in the whole imaging process. Images from low and ultra low permeability formations in the Western Canada Sedimentary Basin are compared with images from other low and ultra low permeability formations reported in the literature. As powerful as these nanoscale capable microscopes are, they all have limitations due to the high instrument cost, limited access and time consuming imaging process. As a result it is difficult and impractical to obtain statistical significant data. To make these instruments of practical value to geoscientists and petroleum engineers, methods and models need to be developed to build a bridge from detailed nanoscale structures to typical lab/field measurements and practical geoscience and engineering-scale applications. In this paper, we propose the concept of a multiple porosity model for evaluation of shale formation based on our observations of the nanopore structure of shales. This includes a model for determining the porosity exponent m in shales and water saturation evaluation. Water saturation curves based on this model are plotted on Pickett Plots for both tight gas and shale formations.
Continuous studies in this area are needed to further explore shale structure in fine detail in order to understand the role of nanopores on shale gas production.
Unconventional gas is stored in extensive areas known as Basin Centered Continuous Gas Accumulations. While the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor.
To help unlock these resources, this paper presents a new and more accurate way of simulating multi-stage hydraulic fracturing in horizontal wells in three dimensions (3D) using single and dual porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic fracturing job is accurately modeled in 3D, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation (Western Canada Sedimentary Basin).
Traditionally, the most widely used approaches have their roots in semi-analytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures due to pressure depletion results in more realistic production predictions when compared with the case where geomechanical effects are ignored.
The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nano-Darcy scale.
Carbonate rocks are usually characterized by a variety of porosity types resulting from depositional and diagenetic processes. The variation of the pore geometry, connectivity and size controls the electrical properties of carbonate rocks. The cementation exponent (m) is controlled by various properties including pore connectivity and tortuosity whereas the water saturation exponent (n) is more controlled by the pore size and wettability. For exploratory wells in carbonates, it is essential to estimate electrical properties for appropriate formation evaluation. Instead of using only analogues, the models developed in this study are shown to be valid for the evaluation of different rock types in exploration wells. This increases the confidence level in initial estimates of water saturation and hydrocarbons-in-place. A triple porosity model is used to calculate m of complex carbonate reservoirs in the Middle East using conventional well log data. The emphasis is on exploration wells as the uncertainty associated with m generally decreases during the development and production stages of the reservoirs. The carbonate rocks in this study are characterized by a combination of interparticle, fracture and non-connected porosity (e.g., vuggy and fenestral) that changes continuously with depth. This increases uncertainty in the estimation of m because, for this complex composite carbonate system, m can be larger, equal to, or smaller than the cementation exponent of the single porosity matrix blocks (mb). The variation in m depends on the relative contribution of natural fractures, interparticle porosity and non-touching vugs to the total porosity of the triple porosity reservoir. The validity of the model is demonstrated through comparison of porosity types calculated from well logs and from direct sources including core samples and thin sections. A continuous curve of m for the whole carbonate reservoir is obtained using this approach.