Shale plays are anisotropic in terms of their reservoir quality which gets reflected in their productivity. Reservoir qualities like organic richness, thermal maturity, hydrocarbon saturation, the volume of clay, brittleness and pressure affect the productivity of the shale plays. In general, the volume of clay has a negative relationship whereas other parameters listed above have a positive relationship with production. In our study area, we found the deepest wells despite having better rock quality; do not perform like nearby shallower wells. The objective of this study is to understand the not so obvious reason behind underperformance of these deepest wells.
Since the wells are located at a deeper depth and the reservoir temperature is high (90 to 135°C), so we studied the area from clay diagenesis and fluid expansion perspective. We have reviewed the imprints of clay diagenesis with the help of XRD data and core integrated multi min processed wireline logs. We observed an increasing trend of illite, chlorite towards the deeper part of the reservoir along with a decreasing trend of smectite in the same direction which indicates a higher degree of clay diagenesis. Fluid expansion study is carried out with the help of total organic carbon and hydrocarbon saturation. This study indicated a higher degree of fluid expansion (TOC to hydrocarbon generation) in the deepest part.
Subsequently, 1D pore pressure, stress and rock mechanical modeling is carried out to evaluate the effect of a higher degree of diagenesis and fluid expansion on geomechanical parameters (pore pressure, stress and brittleness). 1D modeling reveals that the deeper wells have abnormal pressure, stress and low brittleness, which is primarily due to extra pressure contribution from fluid expansion and clay diagenesis apart from the compaction disequilibrium process. This abnormal stress and reduction in brittlness likely to have created challenges for the applied hydrofrac job in the deepest part resulting to narrow frac geometry. Comparison of hydraulic fracture modeling between a shallow and the deepest wells reveal that the hydraulic fracture geometry in the deepest well is narrower than the shallower well. So we came to the conclusion that the deepest wells are underperforming than the shallower wells despite of their better rock quality due to ineffective fracturing and comparatively narrower fracture geometry.
The impact of clay diagenesis and fluid expansion in shale productivity has not been studied widely. Though many authors have extensively studied the impact of clay diagenesis on permeability and pore pressure, the integration of shale well production is rarely attempted. This work will help the operators to better analyze and understand their shale reservoir from clay diagenesis and fluid expansion point of view before planning the hydrofrac jobs.
Ibrahim Mohamed, Mohamed (Colorado School of Mines) | Salah, Mohamed (Khalda Petroleum) | Coskuner, Yakup (Colorado School of Mines) | Ibrahim, Mazher (Apache Corp.) | Pieprzica, Chester (Apache Corp.) | Ozkan, Erdal (Colorado School of Mines)
A fracability model integrating the rock elastic properties, fracture toughness and confining pressure is presented in this paper. Tensile and compressive strength tests are conducted to define the rock-strength. Geomechanical rock properties derived from analysis of full-wave sonic logs and core samples are combined to develop models to verify the brittleness and fracability indices. An improved understanding of the brittleness and fracability indices and reservoir mechanical properties is offered and valuable insight into the optimization of completion and hydraulic fracturing design is provided. The process of screening hydraulic fracturing candidates, selecting desirable hydraulic fracturing intervals, and identifying sweet spots within each prospect reservoir are demonstrated.
Mudstone (shale) reservoir evaluation and efficient development poses a significant challenge due to the heterogeneous nature of these complex formations. Organic-rich shales are characterized by intricate mineralogy, ultra-low nanoporosity, and nano-darcy permeability making these tight source/reservoir rocks challenging in obtaining economically viable hydrocarbons. Consequently, characterizing and quantifying minerology and intra-/interparticle (non)organic-hosted porosity at the pore-scale, and up-scaling it to the core-scale remains a significant focus of evaluating reservoir quality in shale plays.
Current advances in correlative multi-scale and multi-modal 2D/3D imaging of nanoporous geomaterials, such as shales, provide a tremendous opportunity to characterize and represent these rocks over multiple length scales – from core-to pore-scale. Subsequently, these image datasets can be then used for advanced image analysis and digital rock modeling to reconstruct 2D/3D models used to analyze their petrophysical properties.
In this study, the Mancos Shale from the Uinta Basin – one of the most promising shale plays in the United States (
In recent years, the exploration and production of oil and gas from Bakken formation in Williston Basin have proceeded quickly due to the application of multi-stage fracturing technology in horizontal wells. Knowledge of the rock elastic moduli is important for the horizontal drilling and hydraulic fracturing. Although static moduli obtained by tri-axial compression test are accurate, the procedures are cost expensive and time consuming. Therefore, developing correlation to predict static moduli from dynamic moduli, which is calculated from sonic wave velocities, is meaningful in cutting cost and it makes the unconventional oil and gas exploration and production more efficient.
Literature review indicates such a correlation is not available for Bakken formation. This may be attributed to the extremely low success rate in Bakken core sample preparation and not enough published data to develop correlation to relate dynamic moduli to static moduli. This study measures and compares the moduli obtained from sonic wave velocity tests with deformation tests (tri-axial compression tests) for the samples taken from Bakken formation of Williston Basin, North Dakota, USA. The results show that the dynamic moduli of Bakken samples are considerably different from the static moduli measured by tri-axial compression tests. Correlations are developed based on the static and dynamic moduli of 117 Bakken core samples. The cores used in this study were taken from the core areas of Bakken formation in Williston Basin. Therefore, they are representatives of the Bakken reservoir rock. These correlations can be used to evaluate the uncertainty of Bakken formation elastic moduli estimated from the seismic and/or well log data and adjust to static moduli at a lower cost comparing with conducting static tests. The correlations are crucial to understand the rock geomechanical properties and forecast reservoir performance when no core sample is available for direct measurement of static moduli.
Yu, Hongyan (State Key Laboratory of Continental Dynamics) | Li, Xiaolong (Department of Geology, Northwest University) | Wang, Zhenliang (State Key Laboratory of Continental Dynamics) | Rezaee, Reza (Department of Geology, Northwest University) | Gan, Litao (Northwest University)
Abundant shale oil and gas resources have been discovered in the Zhangjiatan shale of the Yanchang formation in ordos basin in recent years. Zhangjiatan shale is a typical lacustrine shale, which is different from Marine shale in physical properties. Most previous research has focused on Marine shale. In order to understand the rock mechanical properties of Zhangjiatan shale, we conducted dynamic and static elastic properties experiments. We selected argillaceous shale and silty laminae shale in Zhangjiatan shale as samples. In order to obtain the static Young's modulus and Poisson's ratio, we use the triaxial pressure test. We use the dipole log to measure the acoustic velocity down the hole, and then we calculate the dynamic Young's modulus and Poisson's ratio of the sample based on acoustic velocity. Young's modulus of argillaceous shale is slightly smaller than that of silty laminae shale and the Poisson's ratio of argillaceous shale is also smaller than that of silty laminae shale. The brittleness of argillaceous shale are greater than that of silty laminae shale, as a result, argillaceous shale is much easier fracturing under pressure. We plotted the cross-plot of RCS, elastic properties and TOC and reached a conclusion that the mass ratio of clay to quartz and feldspar determined the brittleness and deformability of rock, while organic matters also affected the elastic properties of rock. Therefore, the elastic properties of shale are not controlled by a single factor, instead of multiple factors.
Zhai, Wenbao (China University of Petroleum) | Li, Jun (China University of Petroleum) | Xi, Yan (China University of Petroleum) | Liu, Gonghui (China University of Petroleum) | Yang, Hongwei (China University of Petroleum) | Jiang, Hailong (China University of Petroleum) | Zhou, Yingcao (CNPC Engineering Technology R&D Company Limited)
Shale reservoir heterogeneity is more and more focused during shale gas development, especially deep shale gas reservoir buried in the depth of over 3,500 m. However, the evaluation methods of heterogeneity are not always available and poor applicability. In this study, a Principle Component Analysis (PCA)-Artificial Neural Network (ANN) model was presented. The evaluation steps of the model were also given. The validation of the model was confirmed by using a deep shale gas well located in Weiyuan area of Sichuan Basin, China. The results of the validation show that the model presented in this study can be in good agreement with the assessed values of heterogeneity obtained from microseimic events. The developed model's effectiveness was tested by comparing the results acquired from ANN without PCA, where the PCA reduces the dimension of input parameters to improve results of PCA-ANN over 80%. Therefore, the PCA-ANN model can help the engineers evaluate the deep shale reservoir heterogeneity, which provides a tool to give preliminary recommendations of the likelihood of improving the effectiveness of hydraulic fracturing. Implementation of the proposed model can serve as a cost-effective and reliable alternative for the deep shale reservoir.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Alsaba, Mortadha T. (Australian College of Kuwait) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids)
Oil/gas exploration, drilling, production, and reservoir management are challenging these days since most oil and gas conventional sources are already discovered and have been producing for many years. That is why petroleum engineers are trying to use advanced tools such as artificial neural networks (ANNs) to help to make the decision to reduce nonproductive time and cost. A good number of papers about the applications of ANNs in the petroleum literature were reviewed and summarized in tables. The applications were classified into four groups; applications of ANNs in explorations, drilling, production, and reservoir engineering. A good number of applications in the literature of petroleum engineering were tabulated. Also, a formalized methodology to apply the ANNs for any petroleum application was presented and accomplished by a flowchart that can serve as a practical reference to apply the ANNs for any petroleum application. The method was broken down into steps that can be followed easily. The availability of huge data sets in the petroleum industry gives the opportunity to use these data to make better decisions and predict future outcomes. This paper will provide a review of applications of ANNs in petroleum engineering as well as a clear methodology on how to apply the ANNs for any petroleum application.
Review our data policy for information about these graphics and how they may be used. Integrated Historical Data Workflow: Maximizing the Value of a Mature Asset Industry studies show that mature fields currently account for over 70% of the world’s oil and gas production. Increasing production rates and ultimate recovery in these fields in order to maintain profitable operations, without increasing costs, is a common challenge. This lecture addresses techniques to extract maximum value from historical production data using quick workflows based on common sense. Extensive in-depth reservoir studies are obviously very valuable, but not all situations require these, particularly in the case of brown fields where the cost of the study may outweigh the benefits of the resulting recommendations. This lecture presents workflows based on Continuous Improvement/LEAN methodology which are flexible enough to apply to any mature asset for short and long term planning. A well published, low ...
A Sand Wash Basin well was drilled for an unconventional target for which the measured core properties did not match production for the well. The crushed-rock porosity for the core suggested a bulk-volume hydrocarbon (BVH) of 1.5 to 2.0 p.u., indicating that the stimulation would have to be draining at approximately 400 ft vertically. To resolve this incongruity for further field development, we investigated the validity of crushed-rock porosity and nuclear magnetic resonance (NMR) to accurately assess the resource. Initial results using conventional 2-MHz core NMR yielded results similar to those for crushed-rock porosity. Because unconventional rocks have very fast relaxations in NMR, it was then theorized that with the use of a high-resolution 20-MHz machine, the signal/noise ratio would improve and create a more-accurate quantification of porosity components. The results of using a high-resolution 20-MHz NMR showed a porosity increase from 6.5 p.u. using the Gas Research Institute (GRI) methodology (Luffel et al. 1992) to 14 p.u. on an as-received sample, creating a large increase for in-place calculations. As a result, a process termed sequential fluid characterization (SFC) was developed using high-resolution 20-MHz NMR to quantify all components of porosity (i.e., movable fluid, capillary-bound water, clay-bound water, heavy hydrocarbon, residual hydrocarbon, and free water). This method represents an alternative to crushed-rock methodologies (such as GRI and tight rock analysis) that will accurately quantify movable porosity as well as the other components without the errors introduced by cleaning and crushing. After investigating the application of SFC with the high-resolution 20-MHz NMR, it was identified that other unconventional plays (such as Marcellus and Fayetteville) have an average of 45% uplift on in-place calculations using SFC-based movable porosity. Identifying in-place volumes correctly can vastly improve the characterization of fields and prospects for unconventional-resource development, and, as is shown in this paper, SFC can be used to do so with a great effect on volume assessment in unconventional reservoirs.
Gupta, Ishank (University of Oklahoma) | Rai, Chandra (University of Oklahoma) | Sondergeld, Carl (University of Oklahoma) | Hofmann, Ronny (Shell International Exploration and Production Incorporated)
Hydraulic fracturing is the completion method of choice in unconventional resource plays. Common laboratory protocols for measuring rock strength, Young’s modulus, and Poisson’s ratio typically do not account for moisture content in rocks, yet these parameters are critical in fracture designs and are greatly affected by rock moisture content.
The process of water weakening is particularly complicated in shales because of the presence of both organic matter and inorganic minerals, such as clays, silica, and calcite. We study the effects of spontaneous fluid imbibition (brine and dodecane) on Young’s modulus and hardness in shales using nanoindentation. The shales studied include Marcellus, Woodford, Eagle Ford, and Wolfcamp.
A key objective was to compare the weakening effects of 2.5 and 7.5% KCl brine solutions vs. dodecane. Our measurements show that irrespective of the shale wettability, brine led to a greater reduction in Young’s modulus (45% reduction in Marcellus, 25% in Woodford, 12% in Eagle Ford, and 21% in Wolfcamp) than dodecane (25% reduction in Marcellus, 17% in Woodford, 4% in Eagle Ford, and 3% in Wolfcamp). Increasing the concentration of the clay stabilizers, such as KCl, led to lower weakening. On the basis of these measurements, it seems that wettability also plays a role in water weakening. Marcellus, being strongly water-wet, experienced the greatest reduction in Young’s modulus and hardness. On the other hand, the Eagle Ford samples, being predominantly oil-wet, experienced the least reduction in Young’s modulus and hardness. The Wolfcamp and Woodford samples, being mixed-wet, experienced moderate reductions in Young’s modulus and hardness.