bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of Various Rate-Decline Analysis Models for Horizontal Wells with Multiple Fractures in Shale gas Reservoirs
Authors: Miao Yanan , Li Xiangfang , Lee John , Zhao Chaojie , Zhou Yunjian , Li Han , Chang Yucui , Lin Wenji , Xiao Zhihua , Wu Nan 
Published: June 2018

Abstract
In recent years, improving the accuracy of production forecast in unconventional reservoirs has been of growing interest to oil and gas industries. Decline curve analysis (DCA) models have been recognized as the most efficient and easiest approaches to estimate gas rate. However, fluid flow regime and well rate decline curves are highly affected by the geological properties of formations. Therefore, the selection of DCA models based on completion designs and geological properties of formations is important for production rate prediction.
Traditional DCA methods, particularly Arps' decline model, was originally developed for predicting boundary dominated hydrocarbon well rate decline, which differs from the dominant long-duration transient flow regime in shale reservoirs. The Stretched Exponential model, the Duong model, the Arps model with a minimum terminal decline rate and the scaling method by Patzek were developed to match and forecast wells with transient flow followed by boundary dominated flow (BDF). In this paper, firstly we developed a new model to estimate production in shale gas reserviors by considering both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas based on the traditional equation of rate versus square-root-of-time. This proposed model can provide better fits to data in transient linear flow regimes. In addition, a systematic analysis of numerical simulation cases in CMG were performed to compare with the traditional model.
The results demonstrated that, in most cases, our model which is demonstrated in this paper, provide more accurate estimation of reserves for numerically simulated cases compared with the traditional decline methods. Therefore, the work offers critical insights into evaluating production in shale gas reserviors in a more efficient way.
Model of Human Resource Needs for the Upstream Petroleum Sector
Authors: Alleyne Neal A. , Alexander David 
Published: June 2018

Abstract
The petroleum industry needs persons with a wide variety of skills for its efficient operation. A catalogue of these skills is therefore very useful to any entity, be it country or company, entering the petroleum industry. This paper describes the human resource needs of the industry on the basis of the value chain of the industry.
The petroleum value chain starts with activities aimed at searching for and finding petroleum and ends with production and sales of crude oil and natural gas to refineries and end users. The technical needs for each section of the value chain are depicted by a model that describes the skills required from the technician to the professional level in addition to the specialist skills. These specialist skills are not always at the professional level. For each section of the value chain the technical skills are built around a particular discipline such as geoscience or petroleum engineering.
The final result is a three dimensional model with ‘technical complexity’ represented in one dimension, ‘value chain variation’ represented in the second dimension and the different entities in the industry represented by the third or ‘entity’ dimension. Along the ‘entity’ slice of the model e.g. for the regulator, the base skills of the disciplines for each section of the value chain are modified or tuned to the needs of a regulatory body such as the ministry of energy for all sections of the value chain. By way of example, under the prospect generation section of the value chain, the regulator requires geoscientist skills aimed at awarding acreage for exploration, the operating companies require geoscience skills for planning and executing exploration programmes and the service companies focus on the skills for providing exploration services.
The model develops a complete catalogue of skills required to meet the needs of all entities involved in the petroleum industry. This catalogue provides universities and training providers with skills which need to be developed in students in preparation for jobs in the industry.
A Comparative Study of Mathematical Models for Fractured Reservoirs: Anomalous Diffusion and Continuum Approach.
Authors: Karim Md Mostafijul , Hossain M. Enamul , Hashan Mahamudul , Imtiaz Syed 
Published: June 2018

Abstract
This study aims to determine an appropriate representative flow-model of a fractured reservoir after comparing two existing approaches: the anomalous diffusion and the continuum approach. A fractured reservoir is assumed in this paper that drains the fluid in transient condition, to a hydraulically fractured horizontal well. To investigate the comparison, dimensional consistency is maintained for both the anomalous diffusion and the continuum approach. Chen and Raghavan's (2015) model is considered as the anomalous diffusion model with modified boundary conditions. Continuum approach model considers the linear flow in a triple continuum structure that consists of matrix slab, micro-fracture, and hydraulic fracture. An analysis of the pressure response curves and the field data evaluates the proper approach for the analysis of the flow behavior. The solution of the wellbore pressure is derived in Laplace domain and is inverted by the Stehfest algorithm. Slope of the pressure response curve depends on the order of differentiation at the anomalous diffusion model. Conversely, the permeability of the hydraulic fracture controls the transient behavior at the continuum approach. The first set of analyses states that the continuum-based model considers the physical structure of the reservoir and increases the accuracy in the prediction of the reservoir behavior; however, more reservoir parameters are required for new continuum those are difficult to be determined. Alternatively, anomalous diffusion approach requires less parameter compare to the continuum approaches, but a high uncertainty exists in the precise determination of the order of the differentiation or the fractal exponent. The anomalous diffusion shows a good agreement with the synthesized field data at the early time whereas the continuum approach matches better at late time response.
Polymer Flooding Application in Trinidad Heavy Oil Reservoirs
Authors: Dukeran Rajiv , Soroush Mohammad , Alexander David , Shahkarami Alireza , Boodlal Donnie 
Published: June 2018

Abstract
The objective of this paper is to assess the application of polymer flooding in Trinidad heavy oil reservoirs. Uncertainty analyses on several synthetic models have been performed to evaluate how variations in reservoir properties affect the oil recovery factor (RF) and Net Present Value (NPV).
Three (3) phases were conducted for the polymer flooding assessment. Phase 1 included a core flooding simulation to assess the oil viscosity sensitivity region and the ranges of polymer concentration for optimization. Phase 2 carried out uncertainty analysis using synthetic models to optimize polymer flooding with respect to NPV. Phase 3 discussed more detail analysis of parameters effects and confirmed the observations in previous cases using analytical approach.
Three types of polymer were used in the models, Flopaam 3130S, 3430S and 3630S. In core flooding simulation, optimal range of polymer concentration was estimated between 500ppm to 5000ppm. On recovery-viscosity plot, a high viscosity oil requires a higher polymer concentration to have higher recovery. Our results showed that this trend was not always true mainly due to the low reservoir fracture pressure, since a higher concentration and/or a higher molecular weight polymer require higher injection pressure. Uncertainty analysis in Phased 2 to 3 indicated that °API /viscosity, depth, permeability and polymer concentration had the highest effect on RF and NPV.
This paper also presents optimal polymer concentration versus oil viscosity for Trinidad oil reservoirs. Moreover, this work determines the reservoirs where the polymer flooding is applicable and recommend proxy models to estimate RF and NPV versus reservoir parameters.
A Novel Dual Isolation System for Deep Water Injector Standalone Screen Completions
Authors: Roane Tom , Bourgneuf Patrick , Johnson Kenneth , Williams Mark , Chaloupka Vladimir 
Published: June 2018

Abstract
A major operator manages multiple, multiwell deep water projects in West Africa. For two such projects in Congo and Nigeria, it was determined that sand control was necessary and a stand-alone screen (SAS) completion was an efficient and cost-effective means for providing sand control for the majority of wells in both projects. This paper describes a new and unique feature of the SAS completion, called the Dual-Isolation Assembly (DIA), which addresses many challenges, and its application in Nigeria on the Egina Project.
Standard SAS completions incorporate a circulation path down the workstring, through the float shoe, and back to surface through the workstring by casing annulus for circulation, pressure maintenance, and removal of the filter cake at the operation's conclusion. The capability to wash down through the toe of the system while running in the well requires washpipe seals inside the float shoe, which incorporates spring-loaded valves that open during pumping, but close when pumping stops. In addition to the wash-down capability, the washpipe incorporates a shifter for closing an uphole isolation valve with the ability to reopen the valve, if necessary.
For an injector well, the flow path into the formation is through the sand-control screens and float shoe from the inside. The path is the opposite for a producer well, which flows from the formation to inside the screen while the float shoe is closed. Because of the different natures of the flow paths, the float shoe is continuously exercised in an injector well as a result of injection fluid starts and stops. During injection, if the opening pressure of the float shoe spring is exceeded, it could stay open over time, causing loss of integrity of the float shoe. When pumping stops, the flow path into the screen through the float shoe could heave formation particles back into the wellbore, as a result of the reservoir being energized upon injection shutdown. The DIA provides secondary and permanent isolation of the float shoe, as requested by the operator, and is capable of shifting a barrier isolation valve installed in the lower completion to comply with the operator's barrier policy for deepwater wells. The DIA and lower completion design allows the operator to safely place a filter-cake breaker treatment in the open hole after setting a lower completion packer.
In addition to fulfilling the requirements of these SAS completions, the DIA design addresses other potential challenges, such as hydraulic locks and any potential swabbing while manipulating the service tools. This paper describes the evolution of the DIA design and full QA/QC and operational procedures, which led to the successful deployment and excellent functionality of the DIA in 12 completions run to date in Nigeria.
Application of Memory Formalism and Fractional Derivative in Reservoir Simulation
Authors: Hashan Mahamudul , Zaman Tareq Uz , Jahan Labiba Nusrat , Elhaj Murtada , Imtiaz Syed , Hossain M. Enamul 
Published: June 2018

Abstract
Reservoir properties (e.g., porosity, permeability, surface tension, viscosity, fluid saturation, wettability, reservoir thickness, pressure, and temperature) are the function of time. Time variation of rock-fluid properties in a reservoir can be defined as memory concept in the field of petroleum engineering. Introducing memory formalism in reservoir simulation allows to account the time-varying nature of rock-fluid properties and enables reservoir simulator to provide more accurate reservoir flow forecast. The key purpose of this paper is to summarize the details for developing a memory formalism-based reservoir simulator. Within the context of the study, the key concept of memory formalism and fractional calculus are precisely explained. A complete roadmap in preparing a memory formalism-based reservoir simulator is shown with example and application.
A Comparative Analysis of Two Methods of Wax Treatment for a Waxy Oil Well in Southwest Trinidad
Authors: Persad Niran , Hosein Raffie , Jupiter Andrew 
Published: June 2018

Abstract
During oil production, when crude oil flows into a wellbore, pressure and temperature are reduced. The micelle structure of the crude oil is destabilized, allowing paraffin (wax) and/or asphaltene molecules to precipitate into the oil, increasing oil viscosity and allowing deposition in the well tubulars. This causes plugging of production and flow lines which decreases oil production. Wax deposition can be mitigated by the application of passive energy waves or a chemical solvent. Passive energy waves are generated by a tool containing a vibrating quartz and semi-precious metal core. This passive vibrational energy stabilizes the original micelle structure in oil and prevents wax deposition and viscosity changes. A chemical solvent is injected to dissolve and remove wax deposits.
In this study, both methods of wax treatment were applied on a waxy oil well in Trinidad, to determine which was more effective and economical. An average oil production rate of 14.4 barrels of oil per day (bopd) was attained from chemical solvent injection and an average oil production rate of 13.4 bopd from passive energy wave application, resulting in cumulative oil volumes of 374 barrels and 349 barrels respectively. Oil inflow into the wellbore, or Productivity Index, increased significantly from pre-treatment conditions by factors of 10.4 with chemical solvent injection and 8.8 with passive energy wave application. From an analysis using profit per barrel of oil (Netback) economics, the total workover cost for passive energy application, including tool rental and installation costs, paid out in 58 days at an average production rate of 13.4 bopd. The total workover cost for chemical solvent injection, including chemical and injection equipment costs, paid out in 12 days at an average production rate of 14.4 bopd.
Decline curve analysis showed that the historical production from the well followed an exponential decline model. This model was applied to production outputs resulting from both treatments and the analysis showed that the producing life of the well was altered by 19% with passive energy wave application and by 20% with chemical solvent injection. From oil sample testing, passive energy wave application caused an increase in oil API gravity from 22.5 to 28.8 °API and a decrease in oil viscosity from 439.1 to 23.7 centiPoise (cP). Production outputs and economics showed that chemical solvent injection was the more feasible wax treatment option for the waxy well studied. However, passive energy wave application was able to positively alter crude oil properties and showed notable success in preventing wax formation in this well.
An Updated Fractional Flow Model of Low Salinity Water Flooding with Respect to the Impact of Salt Diffusion
Authors: Al-Ibadi Hasan , Stephen Karl , Mackay Eric 
Published: June 2018

Abstract
Low Salinity Water Flooding (LSWF) is an emergent technology developed to increase oil recovery. Many laboratory tests of LSWF have been carried out since the 1990's, but modelling at the reservoir scale is less well reported. Various descriptions of the functional relationship between salt concentration and relative permeability have been presented in the literature, as have the differences in the effective salinity range over which salt content takes effect. This paper focuses on these properties and their impact on the fractional flow of LSWF. We present observations that help characterise the flow behaviour in a more general form, simplifying the interpretation of results. We explain how numerical or physical diffusion of salt affects the velocity of the waterflood front, and how this can be predicted from fractional flow analysis.
We have considered various linear and non-linear shapes of the function relating salinity to relative permeability and different effective salinity ranges using a numerical simulator applied at the reservoir scale. The results are compared to fractional flow theory in which both salt and water movement is assumed to be shock-like in nature.
We observe that diffusion of the salt front is an important process that affects the fractional flow behaviour depending on the effective salinity range. The simulator solution matches the analytical predictions from fractional flow analysis under the condition that the mid-point of the effective salinity range is at the mid-point between the formation and injected salt concentrations. However, an effective behaviour similar to adsorption/desorption occurs when these mid-point concentrations are not coincidental. The outcome is that the fronts representing high and low salinity water travel with altered velocities and at different saturations.
We find that we can predict this behaviour from the input data alone as an augmented form of the fractional flow theory including the concept of retardation or acceleration as occurs for adsorption and desorption for other injectants. We use the analytical solution to the advection-diffusion equation and find that the changes in behaviour depends on the Peclet number.
The result of our work is that we have produced an updated form of the fractional flow model of LSWF, to include the impact of salt front diffusion on the movement of fluids. A new factor is introduced, similar to adsorption in polymer flooding. We have developed a new mathematical formula, empirically, to estimate the magnitude of this factor. The new form can be used to modify the effects that numerical or physical diffusion have on the breakthrough times of high and low salinity water fronts during LSFW. This will improve predictive ability and also reduce the requirement for full simulation.
Estimation of OGIP in a Water-Drive Gas Reservoir Coupling Dynamic Material Balance and Fetkovich Aquifer Model
Authors: Zavaleta S. , Adrian P. M. , Michel Michel 
Published: June 2018

Abstract
Although various novel techniques were developed in reservoir engineering for estimation of hydrocarbons initially in place (HCIIP), conventional material balance still remains as one of the most reliable. Average reservoir pressure is critical input data for material balance, which is usually obtained by well shut-in. Nevertheless, this operation might be restricted due to economic and operational restrictions such as water production in gas wells.
In contrast, daily production data is commonly available and can be used to calculate the HCIIP by applying any production data analysis techniques such as the Dynamic Material Balance (DMB) method. The application of such methods to volumetric gas reservoirs and naturally fractured reservoirs resulted in accurate and reliable estimations. However, for water drive gas reservoirs, where the water influx term should be introduced into the iterative process, research and field case applications are limited.
This paper presents an extension to the DMB technique to water-drive gas reservoirs. A simultaneous estimation of the Original Gas-in-place (OGIP) and the water influx term is achieved by coupling the DMB technique with the Fetkovich aquifer model. Average reservoir pressure estimation can also be attained as a result of the coupled method.
Results were validated by means of numerical simulation on a synthetic model and a field study case. Synthetic production data was generated by a commercial simulator and then analized with the coupled method. The calculated OGIP, water influx volumes and average reservoir pressure resulted comparable to simulator output as they presented a low relative error. Furthermore, application of the coupled method to the field study case yielded comparable results to those obtained by volumetric method.
The Faults in our Fields – Well Count and Placement in a Columbus Basin Gas Field
Authors: Dowlath Joel , Onyeagoro Kachi , Sookal Elizabeth , Quammie Kevan , Srinivasan Ashwin 
Published: June 2018

Abstract
The Enterprise gas field is a discovery in Shell's operated acreage in the Columbus Basin off the east coast of Trinidad. It is comprised of two major fault blocks, with an exploration well in the smaller one and an appraisal well in the larger one. The larger fault block is further broken up by minor faults. The potential compartmentalization of this fault block is the major uncertainty in the development of the Enterprise field.
The development plan called for one or two wells to be drilled in the Enterprise field. Detailed mapping of each of the minor faults and analysis of log and pressure data from the wells was used to determine how well connected the various segments are. Using relationships derived from a global database and Vshale logs from offset wells, a range of fault transmissibility multipliers was derived for each fault based on calculated shale gouge ratios and mapped fault throws.
Results of the dynamic fault seal analysis were integrated with dynamic simulation and showed that using base case fault transmissibility multipliers, for all segments where there is reservoir-reservoir juxtaposition across the minor faults, there will be connectivity and the larger fault block can be drained by a single development well. Various combinations of well placements were tested against low, base and high case geological realizations and these were used to determine the optimal development scenario for the field.
Integrated Sand Control Method Design Based on Dsa, Lpsa and Geologic Aspects
Authors: Peña Gerado , Chaparro Humberto , Rodriguez Inti , Azuaje Evelyn 
Published: June 2018

Abstract
Design a completion system for sand control based on top technology as an alternative to the slotted-liner completions systems currently installed in extra heavy oil producing wells in unconsolidated formations.
The methodology and design are based on the resulting interpretations of Dry Sieve Analysis (DSA), Laser Particle Sieve Analysis (LPSA), and geological considerations. Based on the results of these analyses, uniformity coefficients were calculated and grain size sorting results were used to validate the completion criteria, the system type, and the open area to be used. Once these criterions were selected, the Sand Retention Test (SRT) was utilized in the laboratory to verify the performance of the design using different liner sections and core plugs specific to the area; which allowed the selection of the appropriate system. Quantifying the total recovered barrels with the new completion system was done using a nodal analysis in order to evaluate the cost benefit in a typical well.
As result of the interpretations of the tests, it was determined that the open area size of the completion system should be 200 μm, being estimated by the D10 obtained by the DSA realized to the core "A" of the Lower Morichal Formation. With the LPSA realized to the core "B", the quantity of thin grain movables less than 45 μm was estimated for the Lower Morichal Formation. All of these criteria were unified to select the completion method best suited for sand control. The results shows that the best option is metal mesh screen, which offer 150% more flow area in comparison with the slotted liner which translates to a recovery of 10% in production according to nodal analysis simulations.
While current design practices sometimes take into consideration grain size distribution and sorting, this paper highlights the added benefit of combining this approach with the laboratory results of the DSA and LPSA testing methods to ensure that production recovery is truly maximized.