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Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality. All three can lead to poor decisions regarding which work to undertake, what issues to focus on, and whether to forge ahead or walk away from a project. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders. Examples are provided including corporate, business unit and department case studies. This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets.
Learn more about training courses being offered. Learn more about training courses being offered. This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Learn more about training courses being offered. Current and future SPE Section and Student Chapter leaders are invited to engage and share.
Challenges In Drilling and Completion Of Extended Reach Drilling Wells with Landing Point Departure more than 10,000ft in Light/ Slim Casing Design. New Generation of HTHP Water Based Drilling Fluid Changing Conventional Drilling Fluids Solutions. Take Back Control of Your Capital Project with an EPC 4.0 Strategy Stratigraphical - Sedimentological Framework for the Thamama Group Development in the Western UAE Based on the Legacy Core Data: How the Key to the Future is Found in the Past. Ultra-deep Resistivity Technology as a Solution for Efficient Well Placement; Geosteering and Fluid Mapping to Reduce Reservoir Uncertainty and Eliminate Pilot Hole-first Time in Offshore Abu Dhabi, UAE. Performance Comparison of two different in-house built virtual metering systems for Production Back Allocation.
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.
The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. The participants are exposed to the analysis of various elements that help in production system starting from reservoir to surface processing facilities and their effect on the performance of the total production system. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Ibrahim, Ahmed Farid (Shear Frac Group LLC) | Ibrahim, Mazher (Shear Frac Group LLC) | Sinkey, Matt (Shear Frac Group LLC) | Johnston, Thomas (Shear Frac Group LLC) | Johnson, Wes (Shear Frac Group LLC)
The most common stimulation technique for shale production is multistage hydraulic fracturing. Estimating fracture geometry is a focal parameter to judge the fracture operation and predict the well performance. Different direct and indirect techniques can be used for fracture diagnostics to estimates fracture geometries. The current study combines fracture measurements and pressure transient analysis to estimate fracture surface area on each stage and to estimate production as a pseudo production log.
The numbers and kinds of fractures were calculated as a function of treating pressures, injection rates, proppant concentrations, and formation properties to compute fracture surface area (FSA). Pressure transient analyses were then conducted with the leak-off data upon completion of each frac stage to estimate the producing surface (PSA). The fall-off data was processed first to remove the noise and water hammering effects. The PTA diagnostic plots were used to define the flow regime and the data were matched with an analytical model to calculate producing surface area.
Tensile and shear fractures are both created during the injection of frac fluids. Shear fractures are caused by movement in already existing natural (fluid expulsion) fractures found in all shale source rocks. Shear fractures form a pressure below the minimum horizontal stress. These shear fractures take advantage of the rock fabric and develop higher surface area than tensile fractures for the same given volumes of water and sand.
FSA is a measure of permeability enhanced area due to hydraulic fracturing. Producing surface area is the resulting effective flow areaconnected to the wellbore. Diagnostic plots showed a linear and radial flow regime depending on the formation and the completion design. Good correlations were found between PSA and FSA results. In general, higher FSA produces higher PSA. In cases where producing surface area was higher than expected from fracture surface area, communication was found with offset wells. When FSA higher than PSA were found, it was usually caused by increased stress from too close offset wells.
Combining FSA and PSA measurements provides forecasts of production for each stage and helps to optimize well spacing at the end of each frac stage.
This paper presents an optimum way to produce down to depletion a compartmentalized reservoir in offshore deep environment by considering geomechanical stress-deformation mechanisms and associated problems. The case study is for a faulted reservoir zone of the Aphrodite field, located in the Eastern Mediterranean. The study is based on finite element modelling using 2D plane strain analysis that incorporates pore pressure and elastoplastic deformation of reservoir and overburden rock formations using the Drucker-Prager plasticity model. The mechanical properties of the reservoir sandstones were derived from calibration of data obtained from triaxial tests and for the overburden shale layers from acoustic velocities and correlation functions. The compartmentalized geometry was constructed based on seismic data and logging data obtained at the exploration and appraisal phases. The estimated insitu stress field was transformed and applied on the boundaries of the model blocky geometry.
Four different initial and equilibrium depletion scenarios were examined and the obtained results in terms of deformation and effective stresses are compared. The first scenario reflects the initial stress state, the next two intermediate scenarios present non-uniform depletion cases for each fault block, and the fourth scenario presents the case of a uniform depletion. It was found that the uniform depletion of the reservoir compartments creates the least stress contrast in the field and consequently, ensures better control of stress-related impacts during the production. The analysis highlights the local regions of a fault blocks system that potentially suffer by high shear strains that can cause fault reactivation or induced fractured zones but the over-all risk remains low. Furthermore, the analysis establishes relationships between the mean effective stress, volumetric strain, and permeability changes in order to predict the regions with improved transmissibility characteristics or the less permeable compacted rock regions of the reservoir. Overall, the analysis can provide an appreciation of the stress/strain-driven characteristics of the reservoir showing the area of rock compaction tendencies of the faulted blocks and the further deformation in depletion conditions. The presented work demonstrates clearly that a properly calibrated reservoir geomechanical model can be used as a screening tool for examining depletion scenarios of compartmentalized reservoirs, highlighting areas of potential problems such as fault activation, wellbore shearing, reservoir compaction, permeability changes and fault sealing.
Nguyen, Kien (New Mexico Institute of Mining and Technology) | Zhang, Miao (New Mexico Institute of Mining and Technology) | Garcez, Jonathan (Pennsylvania State University) | Ayala, Luis F. (Pennsylvania State University)
Analysis of fracturing water flowback data from hydraulic fractures in unconventional reservoirs plays an important role in determining key fracture properties and predicting future well performance. Current flowback data analysis tools mostly rely on empirical correlations and/or simplified models. This paper presents a semi-analytical, multiphase solution that is applicable to the analysis of not only water flowback but early gas production data of multi-fractured horizontal gas wells. The proposed solution couples a Green's function-based analytical solution for gas flow in matrix with a finite-difference numerical solution for two-phase (gas and water) flow in fracture domain. The validity of proposed semi-analytical solution is verified against simulation results generated using commercial numerical simulators. Inverse analysis techniques are developed based on the proposed semi-analytical solution and presented in the form of type curves. Synthetic case studies show that the proposed type-curve methods can provide explicit and accurate estimation of fracture and reservoir properties, including fracture conductivity, and fracture pore volume. For all case tested, the proposed model is shown to provide accurate and consistent prediction of reservoir performance and estimations of fracture properties while maintaining the simplicity of explicit, iteration-free calculations.
Yu, Wei (Sim Tech LLC and The University of Texas at Austin) | Fiallos Torres, Mauricio Xavier (Sim Tech LLC and The University of Texas at Austin) | Liu, Chuxi (The University of Texas at Austin) | Miao, Jijun (Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin)
Shale field developmentfinds significant challenges when operators have to define optimal spacing of infill wells and further fracture optimization, based on biased understanding of the physical phenomena behind fluid flow in complex unconventional reservoir systems. Although proper modeling has been employed in other studiesto address the detrimental impact of well interference, this study poses how these fracture hits can be beneficial after estimating their impacts in hydrocarbon cumulative recoveries. This study includes spatial variations in fracture conductivity and complexity on fracture geometries of inter-well interference. Furthermore, a non-intrusive embedded discrete fracture model (EDFM) method has been employed to generate these complex scenarios and investigate the impact of well interference multi-well field models. Based on a robust understanding of fracture properties, real production data and wellbore image logging, multiple comparison are performed to address the effects of accounting for inter-well fracture hits on field pressure and production response. First, according to updated production data from Eagle Ford, a model was constructed to perform two (parent) wells history matching. Later, three child wells were included so thatoptimal cluster spacing was recommended considering interwell interference and the distance to thoselong-induced fracture hits. Finally, a field case is presented where the effects of long interwell fractures are evaluated in a nine-well numerical model and contrasted to a scenario without fracture hits. This case is an extension of the work presented by
The simulation results show that long induced fracture hits can be addressed by correlating inter-well wellbore image logs, which will support the occurrence of well interference. Because of these interwell long fracture hits, favorable communication is originated and, thereby, it enhances the oil recovery of the child wells by expanding their drainage influence towards further zones of the reservoir. Likewise, the higher permeabilities in this fracture hits reduce the bottomhole pressure drawdown. As a consequence, the model became a valuable stencil to decide the cluster spacing, and to optimize the hydraulic fracture treatment design. The simulation results were applied to the field successfully to afford significant reductions in offset frac interference by up to 50%.
In acid fracturing treatments, the goal is to create enough fracture roughness through differential acid etching on fracture walls such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the closure stress. The viscous fingering phenomenon has been utilized in acid fracturing treatments to enhance the differential acid etching. For relatively homogeneous carbonate reservoirs, by injecting a low-viscosity acid into a high-viscosity pad fluid during acid fracturing, the acid tends to form viscous fingers and etch fracture surfaces non-uniformly. In order to accurately predict the acid- fracture conductivity, a detailed description of the rough acid-fracture surfaces is required. In this paper, we developed a 3D acid transport model to compute the geometry of acid fracture for acid fracturing treatments with viscous fingering. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. Our simulation results reproduced the acid viscous fingering phenomenon ob-served from experiments in the literature. During the process of acid viscous fingering, high-conductivity channels developed in the fingering regions. We performed parametric studies to investigate the effects of pad fluid viscosities and acid injection rates on acid fracture conductivity. We found that a higher viscosity pad fluid and a higher acid injection rate help acid to penetrate deeper in the fracture and result in a longer etched channel.