bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental and Numerical Study on Cyclic Water Injection in Stress-Sensitive Reservoirs: A Case Study
Authors: Meng Qingbang , Liu Huiqing , Wang Jing , Pang Zhanxi , Kang Botao 
Published: June 2016

Abstract
Cyclic water injection is an enhanced oil recovery method in heterogeneous reservoirs with zero additional cost and simple implementation procedure. It has been successfully applied in a number of oilfields in China, USA and Russia. However, although it is effective in conventional heterogeneous reservoirs, it is still controversial whether it is effective in stress-sensitivity reservoirs, the formation permeability of which changes with variation of the reservoir pressure.
X oilfield is a fractured metamorphic reservoir with high-permeability contrast. During the production and injection, the variations of reservoir pressure would alter the apertures of fractures, and then alter the reservoir permeability, which is defined as stress-sensitivity of permeability. In this paper, the correlation between the stress-sensitive permeability and effective stress was obtained by stress-sensitive testing experiments with the fractured metamorphic cores. Cyclic water injection experiments were conducted with the fractured cores as well. To evaluate the impact of the different parameters involved in the cyclic water injection, we make a sensitivity analysis using a numerical model considering the stress-sensitive permeability. Finally, the projects of cyclic water injection were designed by combining the experimental and numerical results for X oilfields.
The experimental results showed that very little oil increments were achieved for cyclic water injection when the shut-in period was long and the rate of oil production decreased rapidly with increasing cycles. However, if the shut-in period was relatively shorter, additional 3.4% of OOIP (oil originally in place) was achieved. The numerical analysis showed the similar results that the reservoirs pressure had an important effect on the effectiveness of cyclic water injection. During the depressurizing half-cycle, the reservoir pressure should keep above 65% of initial reservoir pressure. When the optimal parameters were applied in the X oilfield, about additional 3.9% of OOIP could be achieved.
This work indicated that cyclic water injection is effective in stress-sensitive reservoirs, however, the reservoir pressure could not drop so much.
Fault Seal Analysis to Evaluate Remaining Potential of Non-Drilled Structures in a Hydrocarbon Field
Authors: Vinhais Gutierrez M. , Roncero L. , Rashwan M. 
Published: June 2016

Abstract
The Onyx field is an undeveloped gas field located in the Poui-Teak Ridge, in the TSP acreage, offshore Columbus Basin, Trinidad & Tobago.
Fault sealing capacity is crucial in the Onyx gas field, which presents clear evidences of hydrocarbon fault leakage along a major fault. This is assessed in this particular case, in order to estimate possible hydrocarbon columns in non-drilled structures within the field. Results are compared against previously published models based on world wide data sets.
The paper approach is based on calibrating computed Shale Gauge Ratio (SGR) for a major fault in the field structure against RFT pressure data across two reservoir fault blocks. It considers Across Fault Pressure Differences (AFPD) as a function of reservoir fluid densities and its columns. An Allan diagram was built for all the major faults of the reservoir structure. In those areas where the diagram shows sand-sand juxtaposition, the relationship between SGR and AFPD is applied. A fault seal failure envelop has been derived from the data and the calibration method is described, making it possible to be applied in fields where lateral sealing faults are major controls in the reservoir trap.
This analysis highlights the likelihood for sands in adjacent fault blocks to be hydrocarbon bearing, and possible hydrocarbon water contacts have been estimated for undrilled structures. This is important for creating possible different success scenarios and for assessing risks for non-drilled blocks in the field.
This type of calibration is relevant and should be assessed on a field by field basis in order to obtain more reliable estimation of remaining potential structures in a hydrocarbon field.
Water Alternating Steam Process WASP Simulation Study in a Colombian Heavy Oil
Authors: Ariza M. C. , Perez A. , Rodriguez Castelblanco A. X. , Munoz Navarro S. F. 
Published: June 2016

Abstract
During the last years the exploitation of heavy oil reservoirs has gained a great attraction, the application of techniques such as continuous steam injection has increased around the world. Although there are many successful projects, inherent problems such as the overriding effect, where steam moves to the top part of the layer decreasing steamflood efficiency occur. The water alternating steam process (WASP) was designed to reduce the problems associated with continuous steam injection, since the water sweeps the remaining oil in the lower parts of the layer, while lowering the reservoir temperature. Due to the limited information on WASP projects, reservoir simulation is a useful tool to determine the feasibility of a WASP process implementation. In this paper the results of a feasibility study are presented in order to perform a WASP process in a Colombian heavy oil field.
The technique was evaluated by numerical simulation on a heavy oil reservoir located in the Middle Magdalena Valley basin. Following the exploitation scheme implemented in other formations of the reservoir, it began with a brief period of cold production followed by a stage of thermal stimulation then to inject steam continuously up to reaching maturity and demonstrating the phenomena of channeling, steam overriding and associated operational problems. The influence of the operating parameters in the WASP technique was determined by sensitivity analysis to then define the optimal scheme of variables to be used during the implementation of the further process to the steamflood.
The simulation results indicate that there was an maintennace in the cumulative oil production as well as a reduction in the project energetic requirements, which means an increase in the net present value (NPV). The economic life of the project was extended given the observed decrease in steam - oil ratio (SOR). The influence of operational variables such as the length and number of cycles, water temperature and water and steam injection rate in the technical performance is also shown.
This work assessed the potential of the water alternating steam process (WASP) for the recovery of heavy oil in a Colombian reservoir, serving as a basis for a subsequent study in a full field model.
Waterflooding Development Strategy Study for a Large Multi-layered Sandstone Reservoir
Authors: Li Y. , Tian C. , Zhu Y. , Li B. , Song B. , Wei C. , Peng H. 
Published: June 2016

Abstract
M1 reservoir is a large multi-layered sandstone reservoir of deltaic environment with oil bearing area around 1500Km2. Sand bodies of M1 is influenced by fluvial, tide and wave, which results in great variations in sand bodies distribution, reservoir quality, vertical and lateral connectivity, etc. Furthermore, M1 is still under primary depletion and current reservoir pressure is around saturation pressure. So how to successfully conduct waterflooding and effectively develop this kinds of reservoirs are very important.
Through detailed geological characterization and dynamic description, 4 reservoir types with different reservoir quality and connectivity are defined and classified. Then 3 equal-probability geological models for M1 are built, which stands for Upside model with good lateral and vertical connectivity, Expected model with medium connectivity and Downside model with poor connectivity. And optimized waterflooding development strategy for different reservoir types with different stacked styles are studied through reservoir simulation based on 3 sector models. The optimized development strategy includes pressure maintenance level, well pattern, well spacing, and perforation strategy.
The results show that the optimized well pattern and well spacing for different reservoir types with different connectivity expectations are different. For reservoir Type A of good reservoir quality, 1000m well spacing with inversed 9-spot pattern is optimum for Upside, Expected and Downside models. But for Type C of poor reservoir quality, 1000m well spacing with inversed 9-spot pattern is optimum for Upside model, while 700m well spacing with 5-spot pattern is optimum for Expected model, and 500m well spacing with 5-spot pattern is optimum for Downside model. For M1 reservoir, because good quality reservoir Type A and Type B are mainly developed in the South part, 1000m well spacing with 5-spot pattern is recommended. While poor quality reservoir Type C and Type D are mainly developed in the North part of M1, 700m well spacing with 5-spot pattern is recommended for this area. For perforation strategy, all zones perforated for both producers and injectors are the optimum for 1000m inversed 9-spot pattern, and only Type C and Type D layers are perforated for the infilling producers of 700m well spacing pattern.
This paper offers a waterflooding development strategy case study for deltaic sandstone reservoirs, which details the optimized development strategy for different reservoir types with different stacked styles and connectivity expectations. It also provides a methodology and reference case for engineers to develop other similar fields.
The Viability of Oil Extraction from Trinidad Tar Sands by Radio Frequency Heating - A Simulation Approach
Authors: Ramcharan T. , Hosein R. , Jupiter A. 
Published: June 2016

Abstract
Trinidad has tar sands resources of about 2 billion barrels of oil on land in the Parrylands/Guapo and Brighton areas. With an oil price of over USD 25 per barrel, commercial extraction of oil from Trinidad tar sands is viable but requires careful study. The relatively small extent of this tar sand (about 10,000 acres and with depths varying from surface to less than 500 feet) and with an oil in place of about 1000 times smaller than the Canadian tar sands, large scale surface mining and in-situ methods such as SAGD and VAPEX processes or their variants are not practical and also for environmental reasons.
In this study we explore the viability of oil extraction from Trinidad tar sands by radio frequency (RF) heating. RF heating does not require an overburden and is cheaper than SAGD and VAPEX and is also environmentally friendly since no steam, water and solvents are needed. Studies have also shown RF heating to be uniform, quicker and with deeper penetration than direct electrical (resistive) heating and an oil recovery between 50 to 80 % can be achieved. Preliminary studies indicated that Trinidad tar sands are wetting and with permittivity in the range 38 −100, which makes it suitable for RF heating.
The COMSOL Multiphysics® software was used to simulate oil sand samples contained within a copper chamber and the RF heating was applied via a dipole antenna. Temperature- time heating plots were generated using an operating frequency of 10 MHz and a current of 50 Amperes. This data and the physical properties of the tar sands were then simulated using the CMG software. The results indicated an oil recovery in the range 30-60%. An energy balance was then conducted and the results show that commercial extraction of oil from Trinidad tar sands by RF heating is viable with an oil price of over USD 25 per barrel.
Trinidad Columbus Basin Permeability Upscaling Transforms
Authors: Ali-Nandalal J. , Baksh K. , Singh S. , Akong S. , Ramlal S. 
Published: June 2016

Abstract
Reservoir permeability is an integral parameter in the prediction of gas well and reservoir performance which is critical in operating a business built on gas deliverability. In the absence of dynamic performance data; core calibrated log permeability is typically used to estimate well deliverability. Historically actual permeability derived via pressure transient analysis indicated the need for further upscaling to the core calibrated log permeability. Two new permeability transforms are proposed for the bp Trinidad and Tobago LLC fields in the Columbus basin in Trinidad. This provides the ability to incorporate upscaling heterogeneities that would not be represented at a core or log scale.
The updated transforms replace a single legacy transform which is no longer applicable since the underlying log calculated permeability method has undergone a refresh and the pressure transient analysis database has also been revised. The updated pressure transient derived permeability-thickness encompassed forty-plus wells from across the basin and was utilized in tuning well models to replicate actual performance and hence provide assurance against forecasted gas rate deliverability.
The transforms have been developed for conventional sands in the Basin and are regional. Since they have been deployed, they have been blind tested with additional pressure transient analysis tests that have so far proven their robustness. This updated transform has proven to be a valuable tool to the business as wells have been designed as primarily big-bore high rate wells with the aim of delivering gas to market with minimal well count.
Injection Well Placement Analysis for Optimizing CO2 Enhanced Gas Recovery Coupled With Sequestration in Condensate Reservoirs
Authors: Narinesingh Jonathan , Alexander David 
Published: June 2016

Abstract
Depleting hydrocarbon reserves and increasing greenhouse gases present a major challenge to the energy sectors. As a result, emphasis needs to be placed on ensuring optimum depletion of known hydrocarbon reserves and reduction of greenhouse gases. This paper presents the effects of various injection well placements on the efficiency of Enhanced Gas Recovery (EGR) and sequestration, using reservoir simulation, in an attempt to optimize EGR coupled with CO2 sequestration.
The compositional simulator CMG-GEM was used to build a reservoir model with a simple 3D geometric shape (cuboid), which was populated with various layers with properties analogous to a real condensate field to improve the accuracy of the flow path modeling. WINPROP was used to create a detailed fluid model.
Using the model as discussed above, the injector placement was varied whilst using a fixed injection pressure of 2000 psi at the end of primary recovery for all scenarios. These well placements included a single vertical injector, two vertical injectors and a single horizontal injector. At the end of each injection scenario, the simulation was run for an additional 1000 years to model the movement of the CO2 plume in the reservoir.
From the simulations, over 60% of the injected CO2 remained in the reservoir. On average, approximately 20% of the injected CO2 was trapped by hysteresis. These relatively high storage values for this research can be attributed to relatively small volumes of CO2 being injected (on average 4 MtCO2 total over 5 years) into a relatively large reservoir (estimated hydrocarbon pore volume of 622.5 MMCF) at low injection pressures. The various injection scenarios resulted in as high as an additional 6.9% condensate recovery over primary production only.
The results of this simple analytical model show that there is the potential to optimize gas and condensate recovery through the use of CO2 injection whilst mitigating a percentage of greenhouse gases. It also provides a base for future well planning models to build upon in order to effectively optimize CO2 EGR and sequestration in condensate fields.
Development Scenarios for Geothermal Energy in the Caribbean
Authors: Rajnauth J 
Published: June 2016

Abstract
Geothermal energy is the heat energy within the Earth, often manifested in geysers, hot springs and volcanoes. It offers an energy source that is far more efficient than fossil-fueled power generation, and it doesn't emit greenhouse gases into the air. Geothermal energy can therefore be very useful in generating electricity however; it currently plays a limited role in the electricity sector. Despite the many challenges to develop geothermal energy presently, future development can contribute significantly to a region's electricity portfolio, thereby decreasing customer costs of electricity, providing a potentially clean resource for power generation and creating a new resource economy.
This paper evaluates the development opportunities for geothermal energy in the Caribbean with focus on main territories with potential geothermal resources. One of the main challenges to producing electricity from geothermal energy is the source of high temperature reservoirs near the Earth's surface. Such resources are rare since heat supply is normally encountered very deep in the earth's subsurface therefore resulting in many geothermal reservoirs being technologically or economically unfeasible to exploit.
In the Caribbean, however there are high-temperature reservoirs that are located close enough to the Earth's surface, making them feasible to exploit and be potentially viable. The Lesser Antilles islands arc in the Caribbean have been largely built by volcanism above a subduction zone. As the Atlantic Plate is being sub-ducted under the Caribbean Plate, it gives rise to active volcanoes making for very attractive geothermal energy exploitation. The data from these estimated resources potential was used to determine development strategies for extracting thermal energy for power generation.
The methodology can involve the use of technology from the oil and gas sector to explore for economically geothermal resources with sufficient high temperatures to warrant development. These include drilling exploration wells, development wells and evaluating reservoir potential.
The analysis shows that development of geothermal energy in the Caribbean with a vast clean resource potential should clearly be considered given the future increases in demand for power generation in the region and the potential to become energy self-sufficient. The potentially lower cost of electricity generation from geothermal energy can mean significant savings for customers in the region.
The various concepts, techniques, methods and technologies used in evaluating and drilling for hydrocarbon, can be successfully used in drilling exploration and development wells for producing thermal energy from the volcanic islands for electricity generation.
Reducing Well Offloading Risks with Dynamic Wellbore Modelling
Authors: Codrington Kofi , Calvert P. 
Published: June 2016

Abstract
Over the past 18 months energy prices have declined more than 50%. This has placed significant constraints on energy companies who are experiencing major declines in operating cash flow while maintaining shareholder distributions. Increasingly, the response has been to cancel or delay capital-intensive projects while attempting to materially improve efficiency and reduce operating costs. Improving the efficiency of Base Production, defined as production from existing wells and fields, has been a particularly effective way for BP to improve or maintain production levels at relatively low cost. This is not without major challenges as Base Production includes fields/wells which are heavily depleted and/or liquid loaded. Offloading these types of wells requires specialized skills and simulation tools one of which is described below.
OLGA or Oil and Gas Simulator is a dynamic multiphase modelling tool which is used to simulate flow behavior of petroleum fluids from the reservoir to onshore gathering systems. It utilizes finite element analysis to divide the well or production system into elements which together create a mesh intersecting at nodes. After boundary conditions are introduced the simulation is completed in a series of several thousand time steps by solving system equations for each element with the outputs from one time step used as the input for the next one.
With this powerful calculation method, engineers are able to investigate the behavior of complex and irregular shaped systems, such as wells and networks, to determine the optimum range of pressures and temperatures to optimize production. For well offloading, dynamic modelling is used to evaluate the offload against various platform, well and reservoir parameters to understand and mitigate risks. Simulations are also completed to ensure new wells either have enough pressure energy to remove completion fluids and flow into the gathering system or to determine if a depressurized volume or reduced system pressures are required.
This approach has positively impacted wedge production delivery for the company as the Subsurface Team is able to better influence well offloading strategy at the early stages of planning therefore reducing instances of production downtime.
Tectono-Stratigraphic Habitat of Hydrocarbons in The Deep-Water Frontier Provinces of Trinidad and Tobago
Authors: Alvarez T. , Mann P. , Wood L. 
Published: June 2016

Abstract
The Trinidad and Tobago deepwater provinces form a structurally complex, frontier basin adjacent to the prolific and well-studied Columbus Basin shelf province that contains over 25 trillion cubic feet (tcf) of gas reserves and has produced over 1 billion barrels (bbls) of oil. The deep horizons in the deep-water area east of Trinidad remain largely underexplored with eight exploration wells to date. We evaluate elements of the petroleum system for the Trinidad and Tobago deepwater area in the context of the tectono-stratigraphic evolution.
We use ~10,000 km of 2D seismic reflection lines which are recorded to depths &gt;12 seconds TWT and well data to interpret the distribution and continuity of tectono-stratigraphic sequences and to identify and constrain the activity of key structural features. We examine the relationships among the tectonic configuration and crustal structures formed along the southeastern margin of the Caribbean – South American (SA) plate boundary zone, the location and timing of depositional systems and sedimentary pathways.
The Trinidad and Tobago deep-water area is located within the ~200-km-long transition zone from westward directed subduction to an east-west oriented strike-slip margin, and it covers an area which includes the transition from the slope province of the foreland Columbus Basin to the southern termination of the Barbados accretionary prism (BAP). Thick Cretaceous strata document the relatively quiescent conditions which existed in the eastern offshore Trinidad area prior to deformation associated with the arrival of the Caribbean plate. The transition to active subduction and collision by the Mid-Miocene is recorded by; (1) basement flexure, (2) segmentation of the broad, relatively quiescent Cretaceous margin into smaller confined foreland and piggy-back basins and, (3) the formation of the BAP composed of thrust blocks of deformed Paleogene to recent sediments which are detached above less deformed Cretaceous sedimentary succession and oceanic basement.
We show how the deformation associated with the transitional tectonic zone in which the Trinidad deep-water area is situated influence the respective elements of the petroleum system. Consequently the deepwater petroleum system differs from the petroleum provinces to the west of the COB and differences are also noted across the sub-provinces within the deepwater area.