The Devonian-Mississippian STACK/SCOOP Play of the Oklahoma Anadarko Basin is a complex assemblage of tight carbonate and siliciclastic strata and an important oil and gas province. In the last decade, prolific drilling has demonstrated significant heterogeneity in the composition of oils produced from STACK/SCOOP reservoirs. This study discusses possible geoscientific explanations for the heterogeneity observed in produced oils and describes how source, maturation, and migration affect their composition.
Geochemical data from 136 produced oils across 12 counties from 4 producing reservoirs is reviewed. Calculated thermal maturity (Rc%) from alkylated polyaromatic compounds shows excellent agreement with oil thermal maturity increasing with increased depth. Oils produced from overpressured reservoirs exhibit a strong relationship between Rc% and Gas-Oil Ratio (GOR), while normal- to underpressured reservoirs exhibit GORs up to an order of magnitude higher at similar Rc%. Light hydrocarbons show that paraffinicity varies starkly with producing reservoir, suggesting compositional fractionation from diffusive migration through tight and argillaceous strata. Conversely, aromaticity varies geographically by Play Region, indicative of changing depositional environments and organic input across the basin. Isoprenoid and sesquiterpane biomarkers indicate all oils are generated by Type II or Type II/III mixed organic matter, but Springer Group reservoirs are charged by a highly argillaceous, non-Woodford source.
The Anadarko Basin is the deepest sedimentary basin in the cratonic interior of the North America with as much as 40,000 feet of Paleozoic sediments (Johnson, 1989). The Anadarko is an asymmetric basin with the deepest sediments bound against the Amarillo-Wichita Uplift to the southwest. The basin is elongated along its west-northwest axis and bound by the Nemaha Ridge to the east and the Anadarko shelf to the west and north.
In the last decade, drilling of Devonian-Mississippian strata along the margins of the basin have delineated one the continent's most successful petroleum resource plays. These areas are colloquially referred to as the
Euzen, Tristan (IFP Technologies (Canada) Inc.) | Watson, Neil (Enlighten Geoscience Ltd.) | Chatellier, Jean-Yves (Tecto-Sedi Integrated Inc.) | Mort, Andy (Geological Survey of Canada) | Mangenot, Xavier (Caltech)
With the development of unconventional resources, the large number and high density of well data in the deep/distal part of sedimentary basins offer new avenues for petroleum system analysis. Gas geochemistry is a widespread and inexpensive data that can provide invaluable information to better understand unconventional plays. This paper illustrates the use of early production gas composition as a proxy for in-situ hydrocarbon phase distribution in the Montney play of westernmost Alberta and northeastern British Colombia. We demonstrate that a careful stratigraphic allocation of the landing zone of horizontal wells is a key step to a meaningful interpretation and mapping of gas geochemical data. The regional mapping of the dryness of early production gas from the Montney formation clearly delineate thermal maturity windows that are consistent with available carbon isotopic data from produced and mud gas. Integrating this mapping with pressure and temperature data also highlights gas migration fairways that are likely influenced by major structural elements and compartmentalization of the basin. In the wet gas window, reported condensate-gas ratios show that the liquid recovery from multi-stage fractured horizontal wells is highly variable and strongly influenced by variations in reservoir quality and stimulation design. Understanding in-situ fluid distribution can help narrow down the number of variables and identifying key controls on liquid recovery. Several examples combining produced and mud gas data illustrate the use of geochemistry to better constrain geological and operational controls on productivity and liquids recovery in the Montney play.
With the rapid development of unconventional resources, a wealth of new data has been released from historically undrilled or poorly documented portions of sedimentary basins. The large number and high density of well data over extended areas of deep/distal parts of these basins offer invaluable information and new perspectives for petroleum system analysis. In the Montney play of Western Canada, the distal unconventional part of the basin covers an area of approximately 65,000 square kilometers and has been penetrated by over 7,000 horizontal wells. Due to sustained low gas price in North America over the past decade, most of the industry activity has been focused on the liquids-rich gas and light oil fairways of this resource play. Production data show that although a broad liquids-rich fairway can be defined at the basin scale, local variations of fluid distribution and reservoir quality strongly affect the liquid recovery from horizontal wells. The geochemical compositions of both produced gas and mud gas provide a powerful tool to investigate those variations, their geological controls and their impact on well performance. While this paper focuses on the fluid distribution, numerous studies have documented the influence of reservoir quality on the liquid recovery in the Montney play (Chatellier and Perez, 2016; Kato et al., 2018; Akihisia et al., 2018; Iwuoha et al., 2018).
Although pore pressure is difficult to measure in low permeability rocks such as shale, it nevertheless has an enormous impact on drilling, hydrocarbon production and geomechanics applications such as hydraulic fracturing and wellbore stability analysis. Pore pressure is, thus, a key parameter for economic development of unconventional reservoirs, for which a predrill pore-pressure estimate is essential. In such reservoirs, changes in lithology occur over vertical depth intervals too small to be resolved using seismic velocities derived by means of normal moveout (NMO) analysis or kinematic inversion because these velocities typically have poor vertical resolution. By comparison, inversion of reflection amplitudes yields higher vertical resolution and greater sensitivity to reservoir properties, due to the influence of density in addition to that of velocity. We present an approach for predicting pore pressure based on P-impedance and the ratio VP / VS of the vertical P-velocity, VP, to vertical S-velocity, VS, obtained from inversion of seismic amplitude variation with offset (AVO) data. Employing P-impedance is analogous to using seismic velocity in conventional seismic-based pore-pressure prediction. However P-impedance from AVO inversion has higher vertical resolution and greater sensitivity than velocities from kinematics. Use of VP / VS allows partial compensation for the influence of variable lithology and mineralogy on Pimpedance.
The reporting of potential resources is essential to assess the future development plan and profitability of a petroleum discovery, but if the project is under appraised and production data are absent, analysts often use analogs for preliminary estimates of technically recoverable volumes. To address this, a workflow is presented for selecting appropriate analogs for unconventional plays and using them to estimate the target play's potential. The proposed technique is demonstrated with a case study of the as-yet undeveloped Bowland Shale, which is the most prominent of the shale plays in the United Kingdom (UK) and is at the early stage of its assessment. The paper describes the current shale gas activity in the UK, highlighting the enviromental constraints placed on would-be Bowland Shale developers, which impact on drilling and production operations and stem from the geographic proximity of urban developments, infrastructure and nature, which limit the size of well pad footprint in the UK where land use is high. Studies have estimated the play's in-place resources for possible future development, but there are few estimates of its corresponding recoverable volumes due to lack of production history. At the outset, a database is created with published minimum-average-maximum ranges of key parameters such as total organic carbon, maturity level, gas filled porosity, permeability, etc. that play a major role in resources estimation and recovery potential for all unconventional plays. A comparison of triangular distributions, key parameter by key parameter, between the target shale play and the analog database, is then carried out using novel graphical and statistical methods to establish a "confidence factor" relating to the analog's viability. The most appropriate analog for the Bowland Shale is chosen from an exhaustive list of North American shale gas plays. Analytical approaches are then used to transform a model of the published type well performance of the selected analog by exchanging key model parameters with those of the target shale play. The paper shows how UK operational constraints can be statistically incorporated into the workflow and have a marked effect on the estimated recovery from the Bowland Shale.
Analytically-derived criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. The criteria are developed considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of longitudinal fractures and another for the initiation of transverse fractures, with respect to the wellbore. In-situ stress state, wellbore pressure, and the formation's mechanical and poroelastic properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
The DITF orientation can be used to constrain the magnitude of the maximum horizontal stress; the most difficult aspect of the in-situ stress tensor to constrain. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. However, transverse CIHF initiation occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Fracture initiation criteria for specific cases presented can be used to predict the orientation of fracture initiation in oilfield operations.
The orientation of CIHFs controls the productivity of hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Fracture initiation often follows a plane different to the final fracture propagation plane. Stress re-orientation in the near-wellbore region may promote fracture initiation of different orientation than the orientation dictated by the far-field stresses. The range of in-situ stress states in which transverse fracture initiation is promoted increases as Biot's poroelastic coefficient,
In the shale oil business, cash flow is a life or death issue. For smaller players, money from investors and lenders is getting harder to find. Keen on Anadarko for a while, Occidental Petroleum is ready to do battle with Chevron for the big independent. What Happened to the Private, Family-Owned Oil Company? When the oil and gas industry goes one way, family-owned Hunt Oil goes the other.
Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.
The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
Fedutenko, Eugene (Computer Modelling Group Ltd.) | Nghiem, Long (Computer Modelling Group Ltd.) | Yang, Chaodong (Computer Modelling Group Ltd.) | Chen, Tong (Computer Modelling Group Ltd.) | Seifi, Mojtaba (Computer Modelling Group Ltd.)
The incorporation of geomechanical effects into the flow simulation is crucial for accurate modeling of unconventional hydraulic fracture systems. Such an incorporation requires a proper construction of stress and pressure dependent permeability/porosity distribution for the whole reservoir domain. Usually this is accomplished by the generation of the correspondent multipliers for porosity and permeability under the assumption of exponential and power law correlations. This task can become complicated for sandstones that display non-linear and inelastic behavior such as hysteresis when subjected to cyclic loading, as it involves many parameters including different moduli for loading and unloading introduced as best fit for experimental values.
We propose a novel Machine Learning approach to this problem based on Multi-Layer Neural Network (MLNN) Modeling of hysteresis nonlinearity caused by Elastic, Dilation, and Compaction compressibility term. MLNN considers the experimentally obtained pressure dependency of permeability and/or porosity for Elastic, Dilation and Maximum Compaction as its training data. After the Network is trained it is used to predict the multiplier curve for any intermediate (i.e. low, middle, and high) compactions. This is accomplished by MLNN hysteresis function which considers the curve forecast as a pattern identification problem. Such an approach is often used for modeling of hysteresis in piezo-actuators and magnetic systems, however it has never been applied to geomechanical modeling before. This paper modifies the classical MLNN in the way that it exactly matches the training data, i.e. honors the boundary conditions for dilation-compaction hysteresis. A history match of a couple of field examples indicate that the proposed model provides a good match with production data.
Cao, Jinrong (The University of Tokyo) | Liang, Yunfeng (The University of Tokyo) | Masuda, Yoshihiro (The University of Tokyo) | Koga, Hiroaki (Japan Oil, Gas and Metals National Corporation) | Tanaka, Hiroyuki (Japan Oil, Gas and Metals National Corporation) | Tamura, Kohei (Japan Oil, Gas and Metals National Corporation) | Takagi, Sunao (Japan Oil, Gas and Metals National Corporation) | Matsuoka, Toshifumi (Fukada Geological Institute)
In this paper, we present an improved method to predict the methane adsorption isotherm for a real shale sample using molecular dynamics (MD) simulation with a realistic kerogen model. We compare our simulation results both to the experiment and to the simulation results on the basis of a simple graphite model, and show how our procedure leads to the creation of more accurate adsorption isotherms of a shale sample at a wide range of pressure. A Marcellus shale sample was chosen as an example to demonstrate how to calculate the adsorption isotherms using MD simulations. Type II kerogen molecular model was selected for the dry gas window. The constructed bulk kerogen model contains mesopores (> 2 nm) and micropores (≤ 2 nm) inside. Ten different mesopore sizes of kerogen nanopore systems were constructed. According to the characteristics of methane density distribution in the simulation system, three regions can be clearly distinguished, free gas, adsorbed gas, and absorbed gas. We show that the adsorbed gas per unit pore volume increases with the pore size decreased. This is similar to previous molecular simulations with graphite model. For predicting the total adsorption isotherm of a real shale sample, both adsorbed and absorbed gas were considered. For the adsorption amount, the calculated adsorption isotherms were averaged based on pore size distribution of that Marcellus Shale sample. For nanopores smaller than 5 nm, we used total organic carbon (TOC) data to weight the absorption contribution in the kerogen bulk (i.e. inside the micropores). The total adsorption isotherm thus obtained from our simulations reproduced experiments very well. Importantly, kerogen model has overcome the difficulties of prediction using graphite models (i.e. an underestimation of adsorption under high pressure conditions) as documented in previous studies. Furthermore, we predicted the adsorption isotherms for higher temperatures. With the temperature increased, lower adsorption amount is predicted. The novelty of our improved method is that it is able to predict methane adsorption isotherm at a wide range of pressure for a shale sample by considering both adsorption in kerogen mesopores and absorption in kerogen bulk. It can be readily used for any shale sample, where the pore size distribution, porosity, and TOC are known. We remark that the above results and conclusion resulted from our simple assumption. Further discussion might be necessary.