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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. 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. Safety leadership focuses on the Human Factors (HF) which complement technical training to optimise reliability, safety, compliance, efficiency, and risks within a team-based environment. The IOGP laid down the HF skills and competencies required, and they form the basis for specialised O&G HF training's delivered by Mission Performance. This 1-day course reviews the key human factors but then also reviews what can be done to accelerate and scale operational roll-out for optimum and sustained impact, including integration with existing safety processes and (reporting) systems, refreshers, assessments, measurements, as well as the role of leadership and culture. 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.
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.
The Eocene C-Sup VLG3676 reservoir is one of the most important oil reservoirs of Western Venezuela. It has a high lateral sedimentological heterogeneity, some sand production issues due to low sandstone cohesion and high stress gradients, and asphaltene precipitation problems. All these features have created production problems since the beginning of the reservoir production, with a drastic impact on the reservoir potential. This has lead to the construction of a compositional/geomechanical model in order to design a palliative strategy. The proposed modeling methodology includes nine phases: 1) Development of the 3D mechanical earth model (MEM) to simulate reservoir compaction; 2) Quality control of the static model, including the relative permeability values; 3) Development of a fluid model that predicts the onset of asphaltene precipitation; 4) Development of a rock-fluid interaction model; 5) Initialization and calibration of the compositional model; 6) Coupling of the compositional and geomechanics models; 7) History matching; 8) Analytical estimation of the onset of sand production; 9) Implementation of an opportunity index analysis for asphaltene precipitation and sand production.
This paper reviews how the Rotary Steerable System (RSS) market has changed over the last two decades. It explores current market forces; specifically the shift in RSS philosophy resulting from ever-improving motor steerable technology. It describes how the need for longer laterals with minimal tortuosity, maximum drilling efficiency, reduced risk of unplanned events, and elimination of AFE overspend, along with the paradigm shift in the directional drilling market seen since 2014, drove the specification for a newgeneration RSS tool. The paper describes the development of a new RSS with a topology and control concept that allows full proportional control of bias from a fully rotating, push-the-bit tool, with the ability to "turn off" any bias during operations where side force is undesirable and to minimize potential tortuosity. It describes how the design team focused on modular design and rapid turn around of tools, in order to maximize utilization and efficiency. Field-test results are included, which demonstrate build and turn at up to 10 /100 ft. and the ability to drill accurate lateral sections. Field results also include the use of ultrasonic imaging while drilling to investigate hole quality.
The objective of the study is to determine the main mechanisms for sand production and to propose completion designs to minimize sand production for HPHT gas wells in the Tarim Basin. Sand production has been a very serious concern in these HTHP gas wells. This paper presents field results for several key wells which are prone to sanding and investigates the possible reasons and mechanisms responsible for sand production. A fully coupled 3D, poro-elasto-plastic sand production model has been developed and applied to study sand production issues for these wells. Sand production data from several wells were analyzed to better understand the conditions under which sand production occurs and conditions under which it is mitigated.
The sand production model was used to model the different completion designs and flow back strategies that were used in the field. The model couples multi-phase fluid flow and elasto-plasticity to simulate pressure transient and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell removal algorithm has been implemented to predict the dynamic (time dependent) sand production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production.
For this study, triaxial tests on core samples have been conducted and the stress-strain curves under different confining stresses are analyzed to obtain rock properties for both the pre-yield and post-yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand production model was run to verify the role played by different factors. It is shown that completion design, rock strength and post failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated BHP change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include, drawdown management, completion and perforation design. In this study, we quantitatively show for the first time that data from HPHT gas wells that suffer severe sand production problems can be modeled and analyzed quantitatively to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.
The objective of the work is to identify zones of abnormal pressures and determine the dynamic mechanical properties of the rock in wells without information of sonic and density logs. In the area of study, geomechanical problems have been detected in intermediate hole sections that make it difficult for drilling operations, thus generating non-productive times. Density log (ρb), compressional sonic log (Δtc) and shear sonic log (Δts) are essential to attack this problem and provide possible solutions.
To determine the pseudo-sonics logs, it was necessary to modify the correlation of L.Y. Faust (1951), introducing a third variable, the clay volume, it was called Faust Modified Correlation. The pseudo-density log was obtained from the G.H.F. Gardner adjusted correlation (1974). The zones of abnormal pressures were identified by comparing the normal compaction train of the sonic log (Δtcn) with the compressional sonic log (Δtc). And finally the dynamic mechanical properties of the rock were determined such as Poisson's ratio (n), Shear modulus (μ), Bulk modulus (K), Young's modulus (E) and Bulk compressibility (C).
The Faust modified correlation showed excellent results of compresional sonic logs, obtaining a correlation coefficient of 93%. The Gardner adjusted correlation as a function of the P wave velocity obtained good results of density logs, with a correlation coefficient of 94%. The zones of abnormal pressures were identified towards the Miocene base with an average pore pressure of 9.17 ppg. In the Pliocene and Miocene high Poisson's ratio was determined that varies between 0.28 and 0.36, and low Young's modulus between 0.85 and 5 Mpsi, this indicates that the rocks are deformed more easily. In the Eocene and Cretaceous, low Poisson's ratio was determined between 0.21 and 0.27, and high Young's modulus between 6.1 and 10 Mpsi, this indicates that the rocks do not easily deform.
In addition, the velocity models of the P wave and S wave (VP and VS) were simplified through graphical methods, where VP is a function of the Bulk modulus (K) and Shear modulus (μ), while VS is a function of the Shear modulus (μ). From these models, cubes of Lamé's parameters (λ, μ), elastic properties and S wave velocity were determined using the velocity cube of the RMS compressional wave of seismic as input data to generate cubes of clay volume and fluid saturation with the purpose of looking for opportunities in exploration areas.
Fines migration is a commonly observed phenomenon in oil and gas wells, but often difficult to duplicate in the laboratory. A suite of labs tests was conducted to gauge the effect that different test conditions have on fines migration and to improve fines migration prediction through updated test strategies. Core tests were conducted on core samples collected from a field in West Africa. Field B shows evidence of fines migration through increased PI and reduced skin after a diesel pump-in, and significant increase in production rates after hydrofluoric (HF) acid treatments. Some of the earlier conventional core tests conducted with cores from the same field failed to predict a potential for fines migration. Hence, a study to optimize current fines migration test methods was initiated. With the new tests, the effect of injected fluid volumes, injected fluid type, test temperature, surge conditions and depletion on fines was investigated. Results from these new tests showed evidence of fines migration as observed in the field, in contrast to the earlier tests conducted using conventional test methods. While the tests confirmed the presence of non-Darcy flow at high injection rates, strategies to exclude the contribution of non-Darcy flow from fines-related formation damage were developed and will be discussed.
This paper presents the workflow and learned lessons during the construction of a fully compositional integrated subsurface/surface model for the Santa Barbara and Pirital fields, which are important oil production units located to the east of Venezuela. In this approach, the numerical reservoir simulation models, wells and surface facilities were coupled in order to obtain production profiles considering both changes in the reservoir conditions and surface restrictions, achieving an assertive planning of asset development.
The applied methodology is based on the construction of more than 150 compositional well models, performing sensitivity analysis to define multiphase flow correlations for vertical pipe and chokes. A network model, which comprises more than 900 Km of lines, 3 main flow stations, and 3 separation levels, was also built in compositional mode honoring line sizes, lengths and elevation changes. Two numerical simulation models represent the most reliable characterization of the main reservoirs. Each model was initialized and ran separately, in order to discard internal inconsistencies. Then, the integration was performed considering the sand face on the wells as the coupling point.
The integrated asset modeling allowed predicting the production behavior of the reservoirs taking into account the constraints of the surface facilities, reducing the uncertainty of forecasts and identifying limitations and bottlenecks at surface level. It was also possible to accurately determine the details of the hydrocarbons streams (NGL) at different pressure stages of the network, which reasonably matched with field data (less than 3% of difference). The result is a versatile tool for the integrated asset management, which allows to sensitize all the elements of the production chain and estimate how each one affect the performance of the asset, discarding the division between departments upstream and downstream and establishing a common management strategy for all disciplines.
The novelty of this work is based on the challenge of building fully compositional coupled models considering giants and complex reservoirs with large surface networks. The proposed methodology and learned lessons will certainly serve as reference for similar future works.
The EoceneFrac area corresponds to a subsoil extension of approximately 230 Km2, located northeast of Lake Maracaibo in the Lagunillas area, where Informal Members B-2-X and B-3-X have been defined as The main oil-producing sands of the Misoa Formation of the Eocene Age, classifying the B-2-X-68 deposit as the second at the western level in crude oil reserves and object of this study. The EoceneFrac reservoir is 24 ° API hydrocarbon and this reservoir is currently the second largest reservoir in the western region. Work on this site began in 1927 and is noted for the fact that it has to be fractured due to its low permeabilities, despite being a shallow production zone. The first fracture occurred in 1959 at the well Years later was the discoverer.
It has a significant consolidation, which aggravates the problem of the low fluidity of the hydrocarbons to the intermediations of the well, the deposit currently has forty-nine (49) wells of which are in different states being active sixteen (16), inactive six (6), abandoned seven (7), three (3) waiting for abandonment and finally seventeen (17) waiting for reconditioning works for the date of January 13, 2013, being the main problem affecting the production of these wells the low mobility.
A Geomechanical study focused on optimizing the fracture designs that arose due to the failed behaviors that had been previously carried out in the B2-X-68 deposit, ceased to function shortly after being made, it is noteworthy that they were found Important parameters of rock and proppant resistance that have a direct impact on collapse of the rock, as well as geopresiones that were not taken into account for initial designs.
Integrated asset modeling (IAM) offers the oil industry several benefits. The next-generation reservoir simulators help achieve faster runtimes, insight into interaction between various components of a development, and can be used as an effective tool in detecting bottlenecks in a production system as well as a constant and more effective communication tool between various departments. IAM provides significant opportunities for optimization of very large or complex infrastructures and life-of-field analysis of production optimization scenarios.
Simultaneous modeling of surface and subsurface components helps reduce time and enhances efficiency during the decision-making process which eliminates the requirement for tedious, time-consuming work and iterations between separate solutions of reservoir and surface networks. Beyond this convenience, this technology makes it possible to reach more robust results more quickly using surface-subsurface coupling. The objective of this study is to outline the advantages and the challenges in using next-generation simulators on simulation of multiple reservoirs in integrated asset management.
Simultaneous simulation of multiple reservoirs adds another dimension of complexity to the process of integrated asset modeling. Several sub-reservoir models can be simulated simultaneously in large fields comprising sub-reservoirs with complex surface systems, which could otherwise become very tedious to handle. In this study, a next-generation reservoir simulator is coupled with an optimization and uncertainty tool that is used to optimize the net present value of the entire asset. Several constraints and bottlenecks in such a large system exist, all connected to one another. IAM proves useful in debottlenecking to increase efficiency of the thorough system. The strengths and difficulties associated with simultaneous simulation and optimization of multiple reservoirs are compared to the more conventional way of simulating the assets separately, thus illustrating the benefits of using next-generation reservoir simulators during optimization of multiple reservoirs.
The results show that simultaneous solution of the surface-subsurface coupling gives significantly faster results than that of a system that consists of separate solution of surface and subsurface. The speed difference becomes more significant when the number of reservoirs simulated is more than one. This study outlines the workflow in setting up the model, the CPU time for each component of the simulation, the explanation of each important item in this process to illustrate the incremental benefits of use of next-generation reservoir simulators in simulating multiple reservoirs with surface facilities taken into account.
Although the use of next-generation simulators are becoming more common, solid examples that illustrate the benefits of simultaneous simulation of multiple reservoirs with surface facilities under several different constraints like this study are important to prove the use of such tools where it is more convenient to carry out the optimization in a system that handles decision parameters and constraints simultaneously.