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Abstract Steerable drilling motors still dominate US shale drilling applications. Shale well construction is commonly planned with monobore vertical, high dogleg-severity (DLS) curve and lateral sections. Limitations arise in each portion of the wellbore because one single bottomhole assembly (BHA) does not provide optimal results; hence, trips are required to optimize the BHA. The main disadvantage with existing steerable drilling motors is the requirement for high bend-angle settings to drill the high DLS curve portion of the wellbore. The geometry of a high bend-angle motor is only optimal for slide drilling the curve, it is not optimal for drilling the vertical and lateral portions of the wellbore. While drilling the vertical and lateral portions of the well, surface RPM (revolutions per minute) must be limited to reduce the cyclic bending fatigue on the large external bend. Not to mention poor wellbore quality while rotary drilling with a large external bend. To overcome this issue, a new geometry design was required. The new-generation motor uses a tilted internal drive mandrel aligned with a small external bend. This combination delivers the best of both worlds, providing high DLS capability while slide drilling and high surface-RPM capability while rotary drilling (because of the small external bend). Compact embedded drilling dynamics data recorders were used to validate the dynamic improvement of the new steerable-drilling-motor geometry versus older-style geometry with large external bend. The embedded sensors recorded at-point dynamics of shock and torsional response providing detailed comparative data sets during the development phase. The new-generation steerable-drilling-motor technology utilizes point-the-bit rotary-steerable-system (RSS) methods (for example, a tilted mandrel) with conventional steerable-motor methods (for example, an external bend). The combination of the internal tilt and external bend (aligned together) provides a completely new geometry for a steerable motor. This new geometry is beneficial for high DLS sliding capability, high surface-RPM rotary drilling and improved borehole quality (slide/rotate transition and rotary mode). This new steerable drilling motor with enhanced geometry was utilized to prove delivery of vertical/curve/lateral in one run, consistent DLS through the curve and improved tracking in the lateral. The results from development testing (comparing to older-geometry motors) will be described in this paper.
Wu, Qian (ExxonMobil Upstream Research Company) | Penny, Glenn (ExxonMobil Upstream Research Company) | Rao, Sai Sashankh (ExxonMobil Upstream Research Company) | Mollica, Juan (ExxonMobil Business Support Center Argentina) | Samdani, Ganesh Arunkumar (ExxonMobil Services & Technology Pvt Ltd) | Ewelike, Chioma (ExxonMobil Upstream Research Company) | Zeilinger, Sabine (ExxonMobil Upstream Integrated Solutions) | Gupta, Vishwas Paul (ExxonMobil Upstream Research Company)
Abstract Pressurized Mud Cap Drilling (PMCD) technique is typically applied for drilling formations with natural fractures and large vugs that result in severe or total losses. The density of the drilling fluid used in PMCD is slightly below reservoir pore pressure. In the case of very low reservoir pressures below base oil densities (~6.7 ppg), foam can be an option. This paper presents a methodology to develop an oil-based foam system for a PMCD application. The scope includes the descriptions of a foam PMCD application, functional requirements of foam, the development workflow, testing procedures, and modeling that are necessary to qualify a foam for PMCD application. The development methodology first involves identifying the constraints and well conditions of a given PMCD application; these include wellpath, hole and casing sections, reservoir pressure and temperature, surface pumping pressure limits (typically a rotating control device limit), foam stability requirements, etc. The above constraints drive the performance requirements for the foam. Next comes the design of the foam formulation and evaluating its performance against these requirements through various lab tests and modeling efforts, which can include ambient pressure half-life tests for initial screening, static and rotational stability tests at in-situ well conditions, rheology tests, solubility tests, pressure transmission estimates, gas migration estimates, and hydraulics modeling. Example results from the lab tests and modeling are shown to provide more insights into the development process. The proposed methodology may be used as a guide to design a foam drilling fluid for a PMCD application. The iterative nature of the development method is shown and is driven by the functional requirements that are coupled to each other. For example, a more viscous foam may be more stable but it may not be pumpable. Likewise, a less viscous foam may be pumpable but may not be sufficiently stable. Similarly, a highly compressible foam may not be good at pressure transmission to monitor downhole pressure variations as compared to a less compressible foam. In summary, the methodology described in this paper explains the development of an oil-based foam for a PMCD application that satisfies a set of operational constraints and functional requirements while highlighting the major factors that could impact foam performance. The application of foam to PMCD is a new concept and to our knowledge has not been applied in the field; in significantly depleted reservoirs this may become a viable option.
Vidma, Konstantin (Schlumberger) | Bremner, Samuel Edward (Schlumberger) | Ziyat, Sophia (Schlumberger) | Choo, Daryl (Schlumberger) | Abivin, Patrice (Schlumberger) | Yusuf, Temiloluwa Iyenoma (Schlumberger)
Abstract Near-wellbore diversion during acid fracturing or matrix acidizing is widely used to improve reservoir coverage and to save time spent on zonal isolation. It is particularly useful in offshore operations where efficiency is crucial. Diversion is typically achieved by dynamic placement of degradable solid particulates into perforations, wormholes, and/or fractures to divert the treatment fluid to understimulated zones. The diverting material must maintain integrity and mechanical strength during the operation before degrading at the downhole temperature in the presence of stimulation fluids. Whereas currently used materials work very well in a wide temperature range, at temperatures below 140°F (60°C), finding an appropriate diverting material that balances the trade-offs between surface shelf-life, stability during treatment, and fast downhole degradation is a challenge. This paper presents a novel low-temperature diverter that pushes the degradable diverter temperature limit down to 70°F (21°C). The new material was deployed in a matrix acidizing job performed on an injector well in the North Sea. Field deployment was preceded by an extensive laboratory testing program to verify diversion efficiency and acceptable degradation. The novel diverter was deployed in a restimulation treatment of a 10-year-old injection well where BHT was reduced to 70°F (21°C) due to long term injection of cold water. An acidizing treatment was designed to incorporate 4 diversion pills of the novel diversion material. All diversion pills were placed without extra operational time or operational issues. All four pills showed an instant pressure response of more than 250 psi as well as a sustained pressure increase of more than 100 psi, providing an indication of effective fluid diversion. The well was switched to injection mode less than 36 hours after the end of treatment without any flowback, providing a tremendous gain in operational efficiency. The post-treatment injection rate increased by 150% for several days, demonstrating significant and fast diverter degradation, despite the low temperature. The injection rate later stabilized at more than twice the pretreatment injectivity. The results demonstrate the viability of the novel low-temperature diverter in wells with BHT of 70 to 140°F (21 – 60 °C).
Summary Reserves estimation is an essential part of developing any reservoir. Predicting the long-term production performance and estimated ultimate recovery (EUR) in unconventional wells has always been a challenge. Developing a reliable and accurate production forecast in the oil and gas industry is mandatory because it plays a crucial part in decision-making. Several methods are used to estimate EUR in the oil and gas industry, and each has its advantages and limitations. Decline curve analysis (DCA) is a traditional reserves estimation technique that is widely used to estimate EUR in conventional reservoirs. However, when it comes to unconventional reservoirs, traditional methods are frequently unreliable for predicting production trends for low-permeability plays. In recent years, many approaches have been developed to accommodate the high complexity of unconventional plays and establish reliable estimates of reserves. This paper provides a methodology to predict EUR for multistage hydraulically fractured horizontal wells that outperforms many current methods, incorporates completion data, and overcomes some of the limitations of using DCA or other traditional methods to forecast production. This new approach is introduced to predict EUR for multistage hydraulically fractured horizontal wells and is presented as a workflow consisting of production history matching and forecasting using DCA combined with artificial neural network (ANN) predictive models. The developed workflow combines production history data, forecasting using DCA models and completion data to enhance EUR predictions. The predictive models use ANN techniques to predict EUR given short early production history data (3 months to 2 years). The new approach was developed and tested using actual production and completion data from 989 multistage hydraulically fractured horizontal wells from four different formations. Sixteen models were developed (four models for each formation) varying in terms of input parameters, structure, and the production history data period it requires. The developed models showed high accuracy (correlation coefficients of 0.85 to 0.99) in predicting EUR given only 3 months to 2 years of production data. The developed models use production forecasts from different DCA models along with well completion data to improve EUR predictions. Using completion parameters in predicting EUR along with the typical DCA is a major addition provided by this study. The end product of this work is a comprehensive workflow to predict EUR that can be implemented in different formations by using well completion data along with early production history data.
The price of adding oil in shale plays will be rising this fall as the supply of wells that were drilled but uncompleted (DUCs) runs low. In the top five US shale plays, the total has dropped from more than 6,300 DUCs at the peak in the spring of 2020 to around 4,500 now, according to a report from Rystad Energy. That is the lowest since the fall of 2018 when oil prices were far lower than the current $70/bbl. Back then, the current price would have caused drilling to explode and production to rise, but not this year. Drilling is up this year from last year's deep slump, but it is just keeping up with the declines in older wells.
Abstract The goal of this work is to define the proper combination of erosion, proppant concentration, and fluid additives that minimizes the impact of ash layers to well production, based on the properties of the dominant ash layer types. Ash layers in the Powder River, Eagle Ford, and other basins are found to vary in properties, composition, and degree of mineralization. Their broad variability requires a classification based on their properties: compositional, fabric, behavior, and any mitigation solution used for field operations will depend upon the properties and distribution of the most dominant ash layer types in the area of interest. To achieve this goal this work studies swelling testing, with lateral confinement, on intact and crushed samples, and erosion testing during simulated hydraulic fracturing. These characterizations, along with standard industry testing, provide information on the combination of mechanical and fluid mitigation conditions required to retain and optimize production. Introduction Although altered volcanic ash beds can be found in many unconventional reservoirs, including Eagle Ford, Vaca Muerta, Niobrara, and Mowry, each ash bed is different and presents a unique set of complications to hydraulic fracturing operations (Calvin, et al. 2015) (Xu, et al. 2016). The primary concerns with clays are: swelling potential, proppant embedment, and fines migration. Swelling leads to pore plugging while fines migration leads to clogging pore throats, both resulting in reduced permeability (Himes, Vinson and Simon 1989). In addition, clay swelling can lead to proppant embedment, and weak bedding layers may offset the fracture path resulting in pinch outs that reduce fracture connectivity and result in production losses (Calvin, et al. 2015) (Xu, et al. 2016) (Chuprakov and Prioul 2015). Characterization of these altered ash beds is critical to production performance of an unconventional well and can help the decision making for horizontal landing depths, or in choosing mitigation strategies needed during hydraulic fracturing operations.
Smith, Christopher (Advanced Hydrocarbon Stratigraphy) | Pool, Susan (West Virginia Geological and Economic Survey) | Dinterman, Philip (West Virginia Geological and Economic Survey) | Moore, Jessica (West Virginia Geological and Economic Survey) | Vance, Timothy (West Virginia Geological and Economic Survey) | Smith, Timothy (Advanced Hydrocarbon Stratigraphy) | Gordon, Patrick (Advanced Hydrocarbon Stratigraphy) | Smith, Michael (Advanced Hydrocarbon Stratigraphy)
Abstract The distribution of liquid hydrocarbon (HC) resources in the Marcellus Formation throughout West Virginia (WV) is a matter of economic importance for the State of West Virginia and Marcellus operators. Herein, the West Virginia Geological and Economic Survey (WVGES) and Advanced Hydrocarbon Stratigraphy (AHS) have undertaken a project to map the composition and quantities of liquid gasoline range HCs present in drilling cuttings from counties in and neighboring the WV liquids fairway using Rock Volatiles Stratigraphy (RVStrat). Cuttings were analyzed from 12 wells, including air drilled wells, from Doddridge, Marshall, Ritchie, Tyler, Harrison, and Wetzel counties; spud dates range from 1953-2013. Insights into the geographical distribution of liquids quantities and compositions and the regional petroleum system were gained with a focus on the Devonian-aged shales, i.e. the upper and lower Marcellus Formation and the West River and Geneseo shale members of the Genesee Formation. Major results were identification of apparent thermal maturity trends embedded in the liquids composition across the basin where there is a trend of increasing paraffin (alkane) and decreasing naphthene (cycloalkane) content as a function of depth. A trend of decreasing size (number of carbon atoms) of the liquid molecules vs depth was observed in the West River, Geneseo, and upper Marcellus indicative of thermal maturity. The liquids distribution across the Marcellus fits within expectations from production data showing a trend of increasing content moving westward from northcentral WV towards the Ohio River; liquid saturations measured were likely ≤1% of the original subsurface saturation. The liquids content in the Marcellus shows an apparent declining exponential vs depth trend likely linked to the progression of catagenesis. An anomalous well that may have undergone a significant gas migration/expulsion event, resulting in less liquid content and a preferential depletion of the more volatile liquid HC species was identified. There is also a trend of increasing mechanical strength of the cuttings vs depth likely due to compaction; there are differences in mechanical strength as function of when the well was drilled, before or after 2009 (likely due to PDC [polycrystalline diamond compact drill bits); this was the only bias identified due to the age of the sample or mud system used. The value of being able to collect usable and meaningful geochemical data from air drilled wells where the cuttings are several decades old with minimal cuttings material by RVStrat should not be understated; it allows using samples that are typically considered unsuitable and offers unique opportunities for petroleum system assessments.
Razak, Syamil Mohd (University of Southern California) | Cornelio, Jodel (University of Southern California) | Cho, Young (University of Southern California) | Liu, Hui-Hai (Aramco Americas) | Vaidya, Ravimadhav (Aramco Americas) | Jafarpour, Behnam (University of Southern California)
Abstract Robust production forecasting allows for optimal resource recovery through efficient field management strategies. In hydraulically fractured unconventional reservoirs, the physics of fluid flow and transport processes is not well understood and the presence of, and transitions between multiple flow regimes further complicate forecasting. An important goal for field operators is to obtain a fast and reliable forecast with minimal historical production data. The abundance of wells drilled in fractured tight formations and continuous data acquisition effort motivate the use of data-driven forecast methods. However, traditional data-driven forecast methods require sufficient training data from an extended period of production for any target well and may have limited practical use. In this paper, a deep recurrent neural network (RNN) model is developed for robust long-term production forecasting in unconventional reservoirs. As input data, the model takes completion parameters, formation and fluid properties, operating controls, and early (i.e., 3-6 months) production response data. The model is trained on a collection of historical production data across multiple flow regimes, control settings, and the corresponding well properties from multiple shale plays. The proposed RNN model can predict oil, water, and gas production as multivariate time-series under varying operating controls. Once the forecast model is trained, it can be used to obtain a one-step forecast by feeding the model with input well properties, operating controls, and a short initial production. The long-term forecast is obtained by either recursively feeding the model with forecast results from the preceding timesteps or by training the model for multi-step ahead predictions. Unlike other applications of RNN that require a long history of production data for training, our model employs transfer learning by combining early production data from the target well with the long-term dynamics captured from historical production data in other wells. We illustrate our approach using synthetic datasets and a case study from Bakken Play in North Dakota.
Abstract This study presents molecular modeling evidence of crowding effect on diffusion in nanoporous shale reservoirs. Effect of crowding is recognized by the reduction of diffusivity and deviations of diffusion characteristics from those of classical (normal) diffusion under confinement. We used molecular dynamics simulations at 239°F to investigate diffusion of hydrocarbon components in an oil composition resembling that of the Niobrara formation. We estimated diffusion coefficients of the oil and its individual components in 10 nm calcite-wall confinement and compared the results with pure component and bulk (unconfined) diffusion. We have also considered the effects of CO2 and CH4 on the diffusion characteristics to extend our observations to enhanced oil recovery and carbon sequestration applications. Our results indicate that adsorption on calcite walls may cause 1-10% decrease in the diffusion coefficient as a function of the chain length of the hydrocarbon component. We have observed that the interaction among hydrocarbon molecules affects their diffusivity more than their interactions with the wall. Moreover, the effect of confinement was strongly dependent on the composition of hydrocarbons. Compared with their pure-component diffusivities, the mobility of the heavier hydrocarbons increased more relative to that of the lighter hydrocarbons in hydrocarbon mixtures. The preferential adsorption of CO2 specifically improved the diffusivity of hydrocarbons and hinted on the role of adsorption in gas-injection enhanced oil recovery, complementing the decrease in oil viscosity. Most notably, we have observed that the mean squared displacement of the hydrocarbon molecules became a power-law function of time due to molecular crowding and wall interactions indicating anomalous diffusion characteristics. Introduction Advective transport is the usual assumption to simulate production from conventional oil reservoirs. Inherent in this assumption are the continuum and bulk flow idealizations. Increased interest in primary and improved recovery from unconventional reservoirs, and the recognition of the shortcomings of conventional concepts in explaining and modeling unusual flow characteristics in heterogeneous nanoporous media have led to interest in developing appropriate models of flow and transport in unconventional reservoirs. In these reservoirs, the transport phenomenon is dictated by the relative properties of the pore structure (the shape, size, and connectedness) and hydrodynamic radii of the fluid molecules and cannot be defined without consideration of molecular level interactions. While at the limit of large pore to molecular dimension ratios, advective flow may be appropriate to model the bulk transport, at the other extreme of the spectrum, purely diffusive transport may be envisioned. In the case of the coexistence of drastically different pore structures caused by extreme heterogeneity of unconventional reservoirs, an advection-diffusion model should be invoked to describe flow and transport. Although advective flow in larger (micrometer size) pores is well understood, the diffusive processes of hydrocarbon mixtures in complex, heterogenous nanopore structures of unconventional reservoirs have not been documented in full detail.
Abstract Rock volatiles stratigraphy (RVS) has been pioneered and developed over the last ten years to provide actionable information to oil and gas operators based on detailed geochemical analysis of volatile components present in geological samples. In this study, samples of the Mowry Shale from the Ainsworth 13-35 core (Bighorn Basin) and the Poison Spider No. 8 core (Wind River Basin) were characterized by RVS. Results are compared to standard bulk geochemical datasets with the goal of refining RVS interpretation in immature and early oil-window source rocks. The RVS technique applies vacuum extraction to freshly crushed core or cuttings samples to extract and provide quantitative or relative abundance information on hydrocarbons (HC), organic and inorganic acids, noble gases, air components, various sulfur compounds, and water. This includes aliquots extracted under two degrees of vacuum, 20 and 2 mbar, to obtain readily extracted and more tightly held compounds. Analytes are concentrated on liquid nitrogen cold traps (CT). The CT is then warmed, and analytes are released by sublimation point to a mass spectrometer for analysis. Non-condensable gases like methane and helium are analyzed prior to warming. Analysis at different pressures allows for calculation of relative permeability indices and evaluating environments where compounds reside. The RVS datasets demonstrate correlations to other bulk properties, including RVS-derived gas-oil ratios (GOR) and hydrogen index (HI) from programmed pyrolysis, with higher GOR values corresponding to lower HIs and vice versa. Higher volatile HC content was observed in intervals with higher total organic carbon content. The average distribution of C1-C5 compounds is also comparable between the two wells. A low water zone was observed by RVS at the contact between the upper part of the Mowry Shale and the informal Octh Louie sand, where a lateral was landed in the Ainsworth well. In core chips or rock bit cuttings, much of the original porosity remains intact, compared to polycrystalline diamond compact bit cuttings, and RVS water data from different extraction pressures relates to pore size and wettability. Water is extracted much more readily in the middle Mowry than the shallower shales and sands in the Ainsworth well, consistent with higher S3 responses and a more hydrophobic rock matrix. Correlations of RVS to well logs and core plug data suggest that the more thermally mature Mowry may have better permeability. RVS data provides information about the quality and type of resource present in the upper vs middle Mowry and their inorganic compositions. Based on HC compositional trends, the upper Mowry appears to have a much less dense resource than the Octh Louie and middle Mowry. The upper Mowry also appears to contain a greater ratio of HC gases vs liquids, greater aromatic content, and possibly fewer small molecule sulfur compounds. The nature of the water release from the rock provides relevant information for production and completions. Other non-HC species inform on biological activity and depositional environment; there is evidence of subsurface biological activity altering the organic matter.