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Abstract Characterization of hydraulic fracture system in multi-fractured horizontal wells (MFHW) is one of the key steps in well spacing optimization of tight and shale reservoirs. Different methods have been proposed in the industry including core-through, micro-seismic, off-set pressure data monitoring during hydraulic fracturing, pressure depletion mapping, rate-transient analysis, pressure-transient analysis, and pressure interference test. Pressure interference test for a production and monitoring well pair includes flowing the production well at a stable rate while keeping the monitoring well shut-in and recording its pressure. In this study, the coupled flow of gas in hydraulic fractures and matrix systems during pressure interference test is modeled using an analytical method. The model is based on Laplace transform combined with pseudo-pressure and pseudo-time. The model is validated against numerical simulation to make sure the inter-well communication test is reasonably represented. Two key parameters were introduced and calculated with time using the analytical model including pressure drawdown ratio and pressure decline ratio. The model is applied to two field cases from Montney formation. In this case, two wells in the gas condensate region of Montney were selected for a pressure interference test. The monitoring well was equipped with downhole gauges. As the producing well was opened for production, the bottom-hole pressure of the monitoring well started declining at much lower rate than the production well. The pressure decline rate in the monitoring well eventually approached that of the producing well after days of production. This whole process was modeled using the analytical model of this study by adjusting the conductivity of the communicating fractures between the well pairs. This study provides a practical analytical tool for quantitative analysis of the interference test in MFHWs. This model can be integrated with other tools for improved characterization of hydraulic fracture systems in tight and shale reservoirs.
Abstract The Walloons coal measures located in Surat Basin (eastern Australia) is a well-known coal seam gas play that has been under production for several years. The well completion in this play is primarily driven by coal permeability which varies from 1 Darcy or more in regions with significant natural fractures to less than 1md in areas with underdeveloped cleat networks. For an economic development of the latter, fracturing treatment designs that effectively stimulate numerous and often thin coals seams, and enhance inter-seam connectivity, are a clear choice. Fracture stimulation of Surat basin coals however has its own challenges given their unique geologic and geomechanical features that include (a) low net to gross ratio of ~0.1 in nearly 300 m (984.3 ft) of gross interval, (b) on average 60 seams per well ranging from 0.4 m to 3 m in thickness, (c) non-gas bearing and reactive interburden, and (d) stress regimes that vary as a function of depth. To address these challenges, low rate, low viscosity, and high proppant concentration coiled tubing (CT) conveyed pinpoint stimulation methods were introduced basin-wide after successful technology pilots in 2015 (Pandey and Flottmann 2015). This novel stimulation technique led to noticeable improvements in the well performance, but also highlighted the areas that could be improved – especially stage spacing and standoff, perforation strategy, and number of stages, all aimed at maximizing coal coverage during well stimulation. This paper summarizes the findings from a 6-well multi-stage stimulation pilot aimed at studying fracture geometries to improve standoff efficiency and maximizing coal connectivity amongst various coal seams of Walloons coal package. In the design matrix that targeted shallow (300 to 600 m) gas-bearing coal seams, the stimulation treatments varied in volume, injection rate, proppant concentration, fluid type, perforation spacing, and standoff between adjacent stages. Treatment designs were simulated using a field-data calibrated, log-based stress model. After necessary adjustments in the field, the treatments were pumped down the CT at injection rates ranging from 12 to 16 bbl/min (0.032 to 0.042 m/s). Post-stimulation modeling and history-matching using numerical simulators showed the dependence of fracture growth not only on pumping parameters, but also on depth. Shallower stages showed a strong propensity of limited growth which was corroborated by additional field measurements and previous work in the field (Kirk-Burnnand et al. 2015). These and other such observations led to revision of early guidelines on standoff and was considered a major step that now enabled a cost-effective inclusion of additional coal seams in the stimulation program. The learnings from the pilot study were implemented on development wells and can potentially also serve as a template for similar pinpoint completions worldwide.
Ajisafe, Foluke (Schlumberger) | Reid, Mark (Lime Rock Resources) | Porter, Hank (Lime Rock Resources) | George, Lydia (Former employee of Schlumberger) | Wu, Rhonna (Former employee of Schlumberger) | Yudina, Kira (Former employee of Schlumberger) | Pena, Alejandro (Schlumberger) | Ejofodomi, Efe (Schlumberger) | Artola, Pedro (Schlumberger)
Abstract Increased drilling of infill wells in the Bakken has led to growing concern over the effects of frac or fracture hits between parent and infill wells. Fracture hits can cause decreased production in a parent well, as well as other negative effects such as wellbore sanding, casing damage, and reduced production performance from the infill well. An operator had an objective to maximize production of infill wells and decrease the frequency and severity of frac hits to parent wells. The goal was to maintain production of the parent wells and avoid sanding, which had the potential to cause cleanouts. Infill well completion technologies were successfully implemented on multiwell pads in Mountrail County, Williston basin, to minimize parent-child well interference or negative frac hits on parent wells for optimized production. Four infill (child) wells were landed in the Three Forks formation directly below a group of six parent wells landed in the Middle Bakken. The infill well completion technologies used in this project to mitigate frac hits included far-field diverter, near-wellbore diverter, and real-time pressure monitoring. The far-field diverter design includes a blend of multimodal particles to bridge the fracture tip, preventing excessive fracture length and height growth. The near-wellbore diverter consists of a proprietary blend of degradable particles with a tetra modal size distribution and fibers used to achieve sequential stimulation of perforated clusters to maximize wellbore coverage. Hydraulic fracture modeling with a unique advanced particle transport model was used to predict the impact of the far-field diverter design on fracture geometry. Real-time pressure monitoring allowed acquisition of parent well pressure data to identify pressure communication or lack of communication and implement mitigation and contingency procedures as necessary. Real-time pressure monitoring was also used to optimize and validate the far-field diversion design during the job execution. The parent well monitored was 800 ft away from the closest infill well and at high risk for frac hits due to both the proximity to the infill well and depletion. In the early stages of the infill well stimulation, an increase in pressure up to 600 psi was observed in the parent well. The far-field diverter design was modified to combat the observed frac hit, after which a noticeable drop in both frequency and magnitude of frac hits was observed on the parent well. This is the first time the far-field diverter design optimization process was done in real time. After the infill wells stimulation treatment, production results showed a positive uplift in oil production for all parent wells at an average of 118%. Also, only two out of seven parent wells required a full cleanout, resulting in savings in well cleanup costs. Infill well production data was compared with the closest parent well landed in the same formation (Three Forks). At about a year, the best infill well production was only 10% less than the parent well with similar completion design and the average infill well production approximately 18% less than the parent well. Considering the depletion surrounding the infill wells, production performance exceeded expectations.
Ji, Qin (Reveal Energy Services) | Vernon, Geoff (Earthstone Energy) | Mata, Juan (Earthstone Energy) | Klier, Shannon (Earthstone Energy) | Perry, Matthew (Reveal Energy Services) | Garcia, Allie (Reveal Energy Services) | Coenen, Erica (Reveal Energy Services)
Abstract This paper demonstrates how to use pressure data from offset wells to assess fracture growth and evolution through each stage by quantifying the impacts of nearby parent well depletion, completion design, and formation. Production data is analyzed to understand the correlation between fracture geometries, well interactions, and well performance. The dataset in this project includes three child wells and one parent well, landed within two targets of the Wolfcamp B reservoir in the Midland Basin. The following workflow helped the operator understand the completion design effectiveness and its impact to production:Parent well pressure analysis during completion Isolated stage offset pressure analysis during completion One-month initial production analysis followed by one month shut-in Pressure interference test: sequentially bringing wells back online Production data comparison before and after shut-in period An integrated analysis of surface pressure data acquired from parent and offset child wells during completions provides an understanding of how hydraulic dimensions of each fracture stage are affected by fluid volume, proppant amount, frac stage order of operations, and nearby parent well depletion. Production data from all wells was analyzed to determine the impact of depletion on child well performance and to investigate the effects of varying completion designs. A pressure interference test based on Chow Pressure Group was also performed to further examine the connectivity between wells, both inter- and intra-zone. Surface pressure data recorded from isolated stages in the offset child wells during completions was used to resolve geometries and growth rates of the stimulated fractures. Asymmetric fracture growth, which preferentially propagates toward the depleted rock volume around the parent well, was identified at the heel of the child well closest to the parent. Fracture geometries of various child well stage groups were analyzed to determine the effectiveness of different completion designs and the impact of in situ formation properties. Analysis of parent well surface pressure data indicates that changing the completion design effectively reduced the magnitude of Fracture Driven Interactions (FDIs) between child and parent wells. Child well production was negatively impacted in the wells where the fracture boundary overlapped with the parent well depleted volume in the same formation zone. This study combines pressure and production analyses to better understand inter- and intra-zone interference between wells. The demonstrated workflow offers a very cost-effective approach to studying well interference. Observing and understanding the factors that drive fracture growth behavior enables better decision-making during completion design planning, mitigation of parent-child communication, and enhancement of offset well production.
Abstract Implementing the IIoT paradigm into the classical oil & gas field OT systems is one of the essential concepts for Digital Oilfield 2.0. The transition in architecture and the corresponding technology changes can create a new cyber-physical security risk profile through alterations in the digital information structure of the oilfield OT system. With the onset of IIoT implementations in the industry, it is an opportune time to review and assess the emerging cyber-physical risk landscape. In the paper, we identified and compared the current oilfield OT logical structures with the designs emerging through the IIoT implementations. The analysis includes extensive reviews of developing standards, such as those proposed by Industrial Internet Consortium, and ongoing published experiences to find the primary points of transition. The security risks stemming from the IIoT implementation appear to raise significant concerns with regard to potentially severe cybersecurity outcomes, which could materially impact the integrity and safety of oilfieldoperations. The study concentrated on the cybersecurity threats that could pose negative physical and operational conditions resulting from loss of visibility and / or loss of control of the operational processes in field facilities. Extensive literature reviews were the basis for identifying the implications of cybersecurity risks in the ongoing stages of integrating the IIoT into the field. The reviews identified the modified strategies for cyber-physical systems, including potential threats and counter measurements for the field IIoT model. However, these proposed strategies still miss a fundamental denominator - the assessments generally ignore that it is the fundamental nature of IIoT structure itself that creates cyber-security vulnerabilities. To investigate further, we performed a contrasting analysis based on specific case studies of field IIoT devices such as the pump-off controller and OT architectures. Three foundational threat implications emerged on the transformation of IIoT architecture into the oilfield: 1)The exponential growth of connected distributed artificial intelligence (DAI) devices enormously increases the complexity of designing the software of each facility and system. 2)The cutting-edge Machine to Machine (M2M) characteristic in the IIoT model pushes the human out of the traditional control and monitor loop. 3)The widespread scale of DAI devices with the unique IP address in the network shifts cybersecurity risks to each connected endpoint. The cornerstone of the distinctive IIoT attributes illustrated in the paper contributes to the potential loss of control, leading to potential for serious damaging operational outcomes in the field. The goal of this paper is to aid oilfield security planning and design processes through animproved recognition of the cyber-physical security impacts emerging from the implementation of IIoT architectures and technologies integration into field OT domains.
Liquefied Natural Gas (LNG) industry is a typical example for which various business models, strategies, and affiliated interests exist, making it highly complex in terms of operations. The extended supply chain, from liquefaction to regasification, combined with multilateral contractual relationships that crossover, make efficient operation a challenging task. Considering barriers such as the volume of transactions, communication hurdles, etc., and the lack of contemporary management tools by shipping companies contrary to other industries, the paper proposes a model structure based on Business Process Modelling (BPM). The proposed BPM concept offers a holistic view of company organization and operations, as well as enables control of key performance indicators. Implementing intelligent computer systems to model an inter-organizational business environment to highlight and overcome such problems, is the ultimate goal of the study. This paper offers a coherent perspective of business process visualization across the midstream section of the LNG supply chain, including roles, tasks and resources. The research highlights commonly used business models, the contractual framework, and the physical processes. The volume of the information leads to knuckle points and dysfunctions related to time, transparency and work assignment. It is underlined that the occurring issues relate to the nature of LNG projects, business policies, safety and compliance issues, document transaction load and mishandling, disputes over SPAs, as well as to subjects of goodwill and partnership, unstandardized procedures executed empirically, and concurring office intervention. The aim of the study is the identification of the aforementioned problems that prevent an LNG shipping company from extracting the added value from its operation.
Dzulkifli, Izyan Nadirah (PETRONAS Carigali Sdn. Bhd.) | M. Yusoff, Amy Mawarni (PETRONAS Carigali Sdn. Bhd.) | Basri, Abdul Hakim (PETRONAS Carigali Sdn. Bhd.) | Jamaludin, Izzuddin (PETRONAS Carigali Sdn. Bhd.) | M. Som, M. Rapi (PETRONAS Carigali Sdn. Bhd.) | M. Akram, M. Faizal (PETRONAS Carigali Sdn. Bhd.) | M. Diah, M. Amri (PETRONAS Carigali Sdn. Bhd.)
Abstract Major reservoirs in Field A namely A-2, A-3U, A-3M, and A-3L, are deposited within a multi stacked channel complex system within Group I in Malay Basin. These reservoirs were previously understood based on existing data to have no or very minimal vertical communication between them and are treated as separate systems. In 2018, three wells were proposed to drain the attic oil in the north region of A-3U reservoir. When drilling these infill wells, it was discovered that the pressure has exceeded initial reservoir pressure although the reservoir has been idle for almost a year prior to the drilling. The results of the multi-rate test of two of the three infill wells that are less than 1 km apart are significantly different from one another. Post drilling, more tests were executed to investigate the connection between the sand. Studies were also done by incorporating the static and dynamic reservoir modeling data. Based on the result of the tests and studies, it was concluded that all of the major sands are connected at some areas. This new finding on the connectivity might be able to explain the additional volume needed to history match some of the reservoirs. Establishing stratigraphy concepts of a reservoir particularly in a channel complex system is an ongoing process, in this case, a brown field of almost 20 years of production. All data including new well data and dynamic data plays a vital role for a better understanding of the reservoir. It is essential to incorporate the updated geological understanding into the static model to have a representative simulation for better history matching and prediction. Moving forward, instead of building a separate grid model for each reservoir, a larger framework consist of intercalated reservoir grids will be built with this new geological understanding for dynamic simulation.
Abstract An augmented reality (AR) system is presented which enhances the real-time collaboration of domain experts involved in the geologic modeling of complex reservoirs. An evaluation of traditional techniques is compared with this new approach. The objective of geologic modeling is to describe the subsurface as accurately and in as much detail as possible given the available data. This is necessarily an iterative process since as new wells are drilled more data becomes available which either validates current assumptions or forces a re-evaluation of the model. As the speed of reservoir development increases there is a need for expeditious updates of the subsurface model as working with an outdated model can lead to costly mistakes. Common practice is for a geologist to maintain the geologic model while working closely with other domain experts who are frequently not co-located with the geologist. Time-critical analysis can be hampered by the fact that reservoirs, which are inherently 3D objects, are traditionally viewed with 2D screens. The system presented here allows the geologic model to be rendered as a hologram in multiple locations to allow domain experts to collaborate and analyze the reservoir in real-time. Collaboration on 3D models has not changed significantly in a generation. For co-located personnel the approach is to gather around a 2D screen. For remote personnel the approach has been sharing a model through a 2D screen along with video chat. These approaches are not optimal for many reasons. Over the years various attempts have been tried to enhance the collaboration experience and have all fallen short. In particular virtual reality (VR) has been seen as a solution to this problem. However, we have found that augmented reality (AR) is a much better solution for many subtle reasons which are explored in the paper. AR has already acquired an impressive track record in various industries. AR will have applications in nearly all industries. For various historical reasons, the uptake for AR is much faster in some industries than others. It is too early to tell whether the use of augmented reality in geological applications will be transformative, however the results of this initial work are promising.
Abstract Subject North Sea oil producing well has developed sustained casing pressure in the A-annulus, resulted in well being shut-in for around 3 years. Several attempts were made to understand the source of the tubing-to-annulus communication, however remediation actions based on the conventional intervention techniques were not successful, leak location was not isolated and sustained annular pressure remained. This resulted in deferral of oil production and costs incurred due to unsuccessful intervention and remediation techniques. As the well was already equipped with the permanent fibre optic cable for the communication with the downhole pressure gauge, an alternative opportunity was taken to detect leak location by repurposing the cable for the use of Distributed Acoustic Sensing (DAS) technology along with latest pattern recognition techniques. This approach is based on decoupling of fluid movement signature from the background noise and use pattern recognition algorithms to construct fluid flow logs across entire length of the fibre, displaying character and evolution of fluid noise through depth and time. Performed acquisition program allowed to activate the leak, presence of which was clearly visible on the wellhead and A-annulus pressure data. DAS-based acoustic flow logs allowed to clearly identify the exact location of the leak points and additionally provided an understanding to the reasons of failure of remediation methods based on the interpretation of conventional tool results. Remediation strategy based on the insights provided by DAS succeeded to isolate leak points with no further pressure build-up observed in the A-annulus. As a result, operator was able to return to production the well that has been shut-in for three years. This allowed to reinstate 1mbod in production, restore well primary barriers and reduce operational spend through cancellation of further well interventions. This technology offers a new method of acoustic data processing on DAS that extracts valuable insights to identify the source of fluid flow and flow pathways, providing an ability of capturing events behind multiple casing strings.
Summary Alternate or out-of-sequence fracturing (OOSF) has been field tested in western Siberia in 2014 and in western Canada in 2017, 2018, and 2019, with operational success and positive well-production performance. It is conducted by fracturing Stage 1 (at the toe) and then fracturing Stage 3 (toward the heel), followed by tripping back to place Stage 2 (center fracture) between Stages 1 and 3 (outside fractures). During placing the center fracture, OOSF can exploit the reduced stress anisotropy to effectively activate the planes of weakness (natural fractures, fissures, faults, and joints) to potentially create failure surfaces with different breakdown angles in virtually all directions. This can potentially lead to branch fractures that can connect the hydraulic fractures to stress-relief fractures that are created while placing the outside fractures, ultimately generating a complex fracture network and enhancing fracture connectivity. Despite prior works on fracture modeling (calibrated by field tests) and geomechanical modeling, a comparative analysis of wellbore-breakdown character and hydraulic-fracture orientation during OOSF is still lacking. Thus, in this study, the solutions to 3D Kirsch equations are provided for both low and high stress anisotropies to analyze the differences in breakdown gradient, failure angle, and fracture orientation under various geomechanical and treatment-design conditions. The consideration is given to an intact rock from an isotropic stress state to high-stress-anisotropy conditions. The results are analyzed in the context of the downhole-measured pressures and temperatures. The results indicate that the reduced stress anisotropy during OOSF leads to favorable treating conditions: With a net fracture-extension pressure greater than the reduced stress anisotropy, fracture complexity can be created by allowing the fracture to grow with different failure angles. Also, a well can be drilled and fractured at any inclination or azimuth with favorable breakdown gradients of 45 to 85% of the overburden gradient. The reduced stress anisotropy can also trigger some challenges. The near-well stress-concentration effects can become more pronounced, promoting longitudinal fracture creation. For treatments with tortuosity greater than the stress anisotropy, longitudinal fractures can be created instead of transverse fractures because the tortuosity is transmitted to the wellbore body and not into the fractures. In this case, to initiate transverse fractures, either the wellbore must intersect the pre-existing transverse notches or the near-well pore-fluid pressure must exceed the axial stress and rock strength (before the hoop stress reaches the tensile failure point). In addition, the fracture might lose directional control and follow any path of weakness. Hence, the rock-fabric effects become more dominant under a low-stress-anisotropy regime, which means that with no pre-existing transverse natural fractures or notches, a longitudinal fracture can be generated at the bottom and top of an intact horizontal wellbore. This is the first attempt in identifying the circumstances that should be avoided for optimizing OOSF through geomechanical modeling and the analysis of the downhole-measured pressures and temperatures to reveal the differences in breakdown character using the Kirsch equations under various geomechanical and treatment conditions during the low-stress-anisotropy regime.