Hu, Hao (Department of Earth and Atmospheric Sciences, University of Houston, Houston, TX) | Zheng, Yingcai (Department of Earth and Atmospheric Sciences, University of Houston, Houston, TX) | Fang, Xinding (Department of Earth and Atmospheric Sciences, University of Houston, Houston, TX) | Fehler, Michael C. (Department of Earth and Space Sciences, Southern University of Science and Technology, Shenzhen, China)
Obtaining information of the spatial distribution of subsurface natural and induced fractures is critical in improving the production of geothermal or hydrocarbon fluids. Traditional seismic characterization methods for subsurface fractures are usually based on the effective anisotropy medium theory, which may not be true in reality where the fracture distribution is non-uniform. In this abstract, we propose to test the double-beam method to characterize non-uniformly distributed fractures that are commonly observed in the unconventional reservoirs. We built a 3D layered reservoir model and the reservoir layer is geometrically irregular and it contains a set of randomly spaced fractures with spatially varying fracture compliances. We used an elastic full-wave finite-difference method to model the wavefield where we treat the fractures as linear-slip boundaries and the recorded data include all elastic multiple scattering. Taking the surface seismic data as input, the double-beam method forms a focusing source beam and a focusing receiver beam toward the fracture target. The fracture information is derived from the interference pattern of these two beams, which gives fracture orientation, fracture spacing, and fracture compliance as a function of spatial location. The fracture orientation parameter is the most readily determined parameter. The beam interference amplitude depends on both fracture spacing and compliance in a local average sense for random fractures. The beam interference amplitude is large when there are dense fractures or the compliance value is large, which is important in the interpretation of the fluid transport properties of a reservoir.
Presentation Date: Wednesday, October 17, 2018
Start Time: 8:30:00 AM
Location: 209A (Anaheim Convention Center)
Presentation Type: Oral
Modeling seismic wave propagation in anisotropic media is critical in the development of advanced full waveform imaging and inversion. This paper presents a new constitutive equation and the corresponding viscoelastic transversely-isotropic (TI) wave equation based on factional Laplacian operators under the assumption of weak attenuation. The fractional Laplacian operators that are non-local in space can be efficiently computed using the Fourier pseudospectral method. We evaluate the accuracy of numerical solutions in a homogeneous transversely isotropic medium by comparing with theoretical predictions and numerical solutions by an existing viscoelastic anisotropic wave equation based on fractional time derivatives. We found that the proposed formulation is able to improve the efficiency of wave simulation in viscoelastic-TI media by an order with maintaining the accuracy.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 205A (Anaheim Convention Center)
Presentation Type: Oral
The objective of the work is to identify zones of abnormal pressures and determine the dynamic mechanical properties of the rock in wells without information of sonic and density logs. In the area of study, geomechanical problems have been detected in intermediate hole sections that make it difficult for drilling operations, thus generating non-productive times. Density log (ρb), compressional sonic log (Δtc) and shear sonic log (Δts) are essential to attack this problem and provide possible solutions.
To determine the pseudo-sonics logs, it was necessary to modify the correlation of L.Y. Faust (1951), introducing a third variable, the clay volume, it was called Faust Modified Correlation. The pseudo-density log was obtained from the G.H.F. Gardner adjusted correlation (1974). The zones of abnormal pressures were identified by comparing the normal compaction train of the sonic log (Δtcn) with the compressional sonic log (Δtc). And finally the dynamic mechanical properties of the rock were determined such as Poisson's ratio (n), Shear modulus (μ), Bulk modulus (K), Young's modulus (E) and Bulk compressibility (C).
The Faust modified correlation showed excellent results of compresional sonic logs, obtaining a correlation coefficient of 93%. The Gardner adjusted correlation as a function of the P wave velocity obtained good results of density logs, with a correlation coefficient of 94%. The zones of abnormal pressures were identified towards the Miocene base with an average pore pressure of 9.17 ppg. In the Pliocene and Miocene high Poisson's ratio was determined that varies between 0.28 and 0.36, and low Young's modulus between 0.85 and 5 Mpsi, this indicates that the rocks are deformed more easily. In the Eocene and Cretaceous, low Poisson's ratio was determined between 0.21 and 0.27, and high Young's modulus between 6.1 and 10 Mpsi, this indicates that the rocks do not easily deform.
In addition, the velocity models of the P wave and S wave (VP and VS) were simplified through graphical methods, where VP is a function of the Bulk modulus (K) and Shear modulus (μ), while VS is a function of the Shear modulus (μ). From these models, cubes of Lamé's parameters (λ, μ), elastic properties and S wave velocity were determined using the velocity cube of the RMS compressional wave of seismic as input data to generate cubes of clay volume and fluid saturation with the purpose of looking for opportunities in exploration areas.
There has been recognition in the oil and gas and mineral extractive industries for some time that a set of unified common standard definitions is required that can be applied consistently by international financial, regulatory, and reporting entities. An agreed set of definitions would benefit all stakeholders and provide increased - Consistency - Transparency - Reliability A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) jointly approved the "Petroleum Reserves Definitions." Since then, SPE has been continuously engaged in keeping the definitions updated. The definitions were updated in 2000 and approved by SPE, WPC, and the American Association of Petroleum Geologists (AAPG) as the "Petroleum Resources Classification System and Definitions." These were updated further in 2007 and approved by SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). This culminated in the publication of the current "Petroleum Resources Management System," globally known as PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and has been used by the US Securities and Exchange Commission (SEC) as a guide for their updated rules, "Modernization of Oil and Gas Reporting," published 31 December 2008. SPE recognized that new applications guidelines were required for the PRMS that would supersede the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. The original guidelines document was the starting point for this work, and has been updated significantly with addition of the following new chapters: - Estimation of Petroleum Resources Using Deterministic Procedures (Chap.
Summary The characterization of natural and induced fractures, in terms of fracture orientation, fracture spacing (or density), and fracture compliance, is critical in reservoir development. Given the multi-scale nature of fracture distribution, the commonly used effective anisotropy assumption may not be valid everywhere. The recently proposed double-beam method has been promising in inverting for spatially dependent fracture network information for a horizontal reservoir layer. However, the inverted results can be biased if the fractured layer is dipping. As a result, it is essential to estimate and include the dipping angle of the fractured reservoir layer in the inversion.
The Piceance Basin is located in western Colorado and covers an area of about 7,100 square miles1. A spoon-shaped basin, sediments reach a maximum depth of about 20,000 feet near the central portion, and encompass rocks ranging in age from Tertiary to Precambian. The basin is bounded by outcrops on the east, west and south, and by uplifts that separate it on the north from the Sand Wash Basin and on the northwest from the Uinta Basin. There are massive tertiary intrusives – laccoliths and volcanics – on the southeastern portion of the basin that have elevated the heat flow there and a massive basaltic flow extended west across a portion of the central basin to form the caprock of the Grand Mesa area. Figure 1 is a geologic map of the Piceance Basin in western Colorado1.
Oil and gas exploration in the Piceance Basin dates to the early 1900’s, with the discovery of the Rangely field in the northwest portion of the basin. With the exception of Rangely and a few other small fields, the basin is dominated by wells that produce natural gas. Oil and gas production from the Piceance Basin Mancos was first established in the Rangely field area, as well2. To date, about 30,000 wells have been drilled and completed in the basin, and the vast majority of those that are active, about 15,000 wells3, are producing from the Upper Cretaceous Williams Fork formation sands of the Mesaverde Group, in the central portion of the basin
Mancos Exploration to Date
Gas production was established from the Mancos B sand along the western flank of the basin, an area known as the Douglas Creek Arch, that separates the Piceance and Uintah basins, near the Colorado-Utah state line. The Mancos B sand is a sandy interval in the upper portion of the massively thick Mancos Group shale. In May 2001, WPX Energy began gas production from the lower portion of the Mancos shale in the central portion of the basin, in its vertical Vassar Heath RMV 229-27 well, at Section 27-T6S-R94W, in the Rulison Field.
To date, about 120 Mancos shale oil and gas wells have been drilled, completed and placed into production, not including the aforementioned Mancos B sand wells located along the Douglas Creek Arch and the wells in the Rangely field area. About 56 of these wells are vertical completions, and about 64 are horizontal completions. Figure 2 shows the total production from these wells, along with the Nymex price of natural gas. Note that exploration for Mancos shale gas wells began around the time that Nymex natural gas prices began to decline, and that since gas prices reached a low in early 2016, Mancos development has been limited to a few wells per year.
Summary In this paper, we investigate the use of spectral decomposition and facies classification on time-lapse data related to a Brazilian pre-salt carbonate reservoir. Synthetic seismic data were generated through petro-elastic modeling (PEM), which is based on a representative geological model and flow simulator dynamic properties. Reservoir pressure and saturation distributions are used that corresponds to periods of time, in which, real time-lapse seismic data will be available. The spectral decomposition method used, is based on a modified matching pursuit algorithm. At this stage, we focus on the interpretation of the spectral decomposition, mainly on geometric effects.
The United States National Science Foundation has funded a Sustainability Research Network (SRN) focused on natural gas development in the Rocky Mountain region of the United States. The mission of this SRN is to provide a logical, science- based framework for evaluating the environmental, economic, and social trade-offs between development of natural gas resources and protection of water and air resources and to convey the results of these evaluations to the public in a way that improves the development of policies and regulations governing natural gas and oil development. In a previous paper (
Wellbore construction methods, especially casing and cementing practices for the protection of fresh water aquifers, have been reviewed in these three basins. The wells in the three basins were classified based on coverage of water and hydrocarbon zones as well as age. The assessment confirms that natural gas migration occurs infrequently, but can happen from poorly constructed wellbores. There has been no occurrence of hydraulic fracturing fluid contamination, which was confirmed by our analysis. The significance of these results is to help quantify the risks associated with natural gas development, as related to the contamination of surface aquifers. These results are helping to shape the discussion of the risks of natural gas development and will assist in identifying areas of improved well construction and hydraulic fracturing practices to minimize risk.
Knowledge of Biot poroelastic coefficient is crucial to geoscientists for a number of applications, including oil and gas exploration and production, and hydrogeology. This in turn requires estimation of bulk and grain modulus or compressibility. Although bulk modulus estimation is a standard laboratory method for shale, no effort was made till date to directly measure grain compressibility in the laboratory. This paper presents a laboratory study to fill this gap. The experimental program described here starts with validation of the technique using aluminum sample. Following this, one Berea sandstone and one shale sample was tested. Finally, using the measured data, Biot coefficient was estimated for shale. General agreement with published literature was observed. However, since none of the reported data was obtained through laboratory measurement, further measurements need be performed for shale and other reservoir rocks.
During deposition and diagenesis, cracks and pores are created in subsurface strata. These void spaces or porosity are in turn occupied with one or more fluid phases ranging from water to liquid or gaseous hydrocarbon depending on depositional/post-depositional environment. Intuitively, the mechanical behavior of subsurface strata filled with fully or partially saturated pore spaces differs from that of a rigid or non-porous rock. The extraction of hydrocarbon results into change in pore fluid pressure in subsurface strata. The processes of drilling and completion impact the existing in situ stress field. This is further complicated when intentional/unintentional production of hydrocarbon occurs as the resulting change in pore pressure once again affects the stress field. The effects of pore pressure change on the deformation around a borehole (Detournay and Cheng, 1988), hydraulic fracturing (Detournay et al., 1989) and slip along active faults (Rudnicki and Hsu, 1988) have been reported earlier. To fully understand this, the theory of effective stress was first proposed by Carl Terzaghi on one-dimensional consolidation of soil which was later extended to three-dimension by Biot (1941). Following this, Geertsma (1957) and Skempton (1961) separately defined the expression for effective stress for a fully saturated material, which was later mathematically derived by Nur and Byerlee (1971). In their work, effective stress is expressed as:
where Pe, Pt and Pp are effective, total and pore pressure, respectively, α is Biot coefficient and K and Ks are bulk and grain modulus. Biot coefficient was subsequently utilized in estimating insitu stress (Thiercelin and Plumb, 1994) as well as in wellbore stability analysis and hydraulic fracture design (Cheng et al, 1993). As revealed in Eq. (2), it requires estimation of both bulk and grain modulus. This in turn involves saturating the rock material with pore fluid which presents a challenge for fine-grained rock like shale. The complex pore structure and nanometer range pore diameter of shale makes the saturation a shale sample in the laboratory significantly longer, making the test protocol impractical. This paper explores an alternative laboratory technique which is simply a variant of the unjacketed compressibility test. The paper begins with a description of the experimental technique in detail. This is followed by presenting the results conducted using an aluminum cylinder, the purpose of which is entirely validation of the experimental technique. The presentation is concluded by reporting results on Berea sandstone and shale and estimating Biot's coefficient for those samples. The results presented here indicates usability of the technique in estimation of grain modulus and hence, Biot coefficient, for shale. The readers should note that as shown in Eq. (2), Biot coefficient is estimated using modulus instead of compressibility, it's reciprocal. Similarly, all laboratory measurements presented in this paper report a modulus value and one can estimate compressibility from them.
Integration of geomechanics test results with well log measurements is a crucial step in developing geomechanical models to estimate in situ stress state, maintaining stable wellbore and design hydraulic fracture. Limited availability of core material severely restricts design of a comprehensive geomechanics test program. Sidewall core plugs, although easier to obtain than conventional cores, suffer from being short relative to the length to diameter ratio specified by ASTM. This paper presents a solution to overcome size issues related via measuring ultrasonic velocity on sidewall core plugs at various stress paths. A unique experimental setup allows measurement of ultrasonic velocity both parallel and perpendicular to bedding. The results were then compared with velocity measurements obtained from sonic logs. It was observed that velocity measured within an isostatic stress path provides the closest match to log velocities, thus increasing confidence in dynamic geomechanics measurements on sidewall plugs and allowing geoscientists and engineers with low budgets to conduct more comprehensive geomechanics analyses.
The value of laboratory testing to enhance our understanding of subsurface geomechanical properties to better explore and exploit a hydrocarbon reservoir is well known (Plumb et al., 2000; Cook et al., 2007). Important parameters that provide baseline information for constructing a geomechanical model of the subsurface include the in situ stress state, strength properties, and stress-strain behavior (Zoback, 2007). Among these parameters, strength and stress-strain behavior can be measured in the laboratory whereas in situ stress can be estimated via a combination of well logs, laboratory and field measurement (Thomsen, 1986; Thiercelin and Plumb, 1994). Thus it is imperative to have good quality laboratory data since that would in turn improve estimation of in situ stress state (Higgins, 2006) and help geoscientists solve wellbore stability issues and hydraulic fracture design. In this direction, ASTM and ISRM provided enormous assistance via creating standard protocols on how to conduct a test in the laboratory.
According to ASTM, core plugs used to estimate stress-strain behavior of rock should have a length to diameter ratio of 2 to 1. The process of acquiring and storing cores is a costly operation and lack of core material constrains laboratory testing and generation of geomechanical parameters. Sidewall cores, acquired by attachments to wireline logging tools provide a cost effective alternative as they can be (a) acquired relatively quickly and (b) can be acquired when there is a failure to collect core by conventional coring techniques (Agarwal et al, 2014). However, samples with a length to diameter ratio of less than 2 to 1 are less suitable for laboratory testing. We report a solution to issues related to shorter core plugs during geomechanics testing. In this paper, ultrasonic velocity was measured on sidewall core plugs through various stress paths. A unique experimental setup allows measurement of ultrasonic velocity both parallel and perpendicular to bedding. The results are then compared with velocity measurements obtained from sonic logs. It is observed that velocity measured within an isostatic stress path provides the closest match to log velocities in most of the samples. The velocities obtained throughout various stress paths were compared and efforts were made to address the discrepancies between them.