bluuebunny/crossref_metadata_2025 huggingface dataset:
Advances in Understanding Wettability of Tight Oil Formations: A Montney Case Study
Authors: Habibi Ali , Dehghanpour Hassan , Binazadeh Mojtaba , Bryan Donald , Uswak Gordon
Published: June 2016

This paper presents comprehensive rock/fluid experiments, by use of reservoir rock and fluids, to investigate wetting affinity of the Montney (MT) tight oil play in the Western Canadian Sedimentary Basin. Wettability characterization is essential for selecting optimum fracturing and treatment fluids by completion engineers and for selecting appropriate relative permeability and capillary pressure curves by reservoir engineers. Application of the conventional techniques for wettability evaluation of tight rocks is challenging primarily because of their extremely low permeability and complex pore structure. The objective of this paper is to develop an alternative laboratory protocol for evaluating the wettability of tight oil rocks reliably.

First, we conducted systematic spontaneous-imbibition tests on fresh core samples from two different wells drilled in the MT formation. We measured the air/brine, air/oil, and brine/oil contact angles for all samples. We used the end pieces of the samples to conduct scanning electron microscopy (SEM) and analysis of the elemental mapping, or energy-dispersive X-ray spectroscopy (EDS). Finally, we investigated the spontaneous imbibition of brine (or oil) into the samples partly saturated with oil (or brine). Both oil and brine spontaneously imbibe into the fresh samples, composed of quartz, carbonates (dolomite/calcite), clay minerals, feldspars, and organic matter. The results indicate that the effective pore network exhibits a mixed-wet behavior. Moreover, brine spontaneously imbibes into and forces the oil out of the oil-saturated samples, whereas oil cannot imbibe into the brine-saturated samples. This indicates that in the presence of both oil and brine, the rock affinity to brine is higher than that to oil.
Optimizing Production from Flowing Wells: Minimizing Flow Restrictions Using Chemicals in Southwest Soldado Oil Field
Authors: Diaz Michael
Published: June 2016

Organic precipitation during the production of hydrocarbons has proven to be a production assurance problem experienced in the majority of oil and gas fields throughout the world. Paraffin and asphaltene deposition occurs in several areas of the production system including: the reservoir, wellbore components including the perforation face and production tubing, surface components such as chokes and on flowlines, and also in production equipment downstream. In an effort to maintain optimum production, removal of existing restrictions is essential, just as minimizing the deposition of same. There is no universally effective treatment for organic deposition. Proper identification of the deposit, design and implementation of the treatment is essential to the cost effective production of oil and gas wells experiencing the problem. The most common methods of removal include: mechanical means, chemicals of various types, heat techniques and micro-organisms. This paper analyzes the results of a chemical treatment exercise executed in the Southwest Soldado Oil Field, an offshore asset owned by the Petroleum Company of Trinidad and Tobago Limited (Petrotrin). A paraffin dispersant-asphaltene inhibitor was applied as a method of cost-effectively optimizing production, in a field within which organic precipitation is inescapable as a result of the crude's nature coupled with conditions necessary for deposition. Successful application of this treatment in eight (8) flowing wells and seven (7) flowline segments resulted in increased production levels within the field, despite the production constraints experienced within the field at the time. As a result of this success, apart from expansion of the exercise and treatment on an annual basis, continuous chemical treatment systems were introduced to the field, as a means of minimizing deposition on flowlines and in flowing and PCP wells.
An Integrated and Reliable Workflow to Determine Critical Rates for Gas and Water Coning in Oil and Gas Reservoirs - A Multi Well Approach, Case Study Pemex, Mexico
Authors: Espinola O. , Guzman J. D. , Mehranfar Reza , Pineda H.
Published: June 2016

Commonly when fields are operated, there are several challenges to face and make profitable the operations, from the reservoir perspective one of the key challenges is when we have undesirable fluids that can cause cost in the operations and make more complex the production. This is the case when we have water or gas production in an oil reservoir or water production of a gas reservoir. First of all the productivity on the well can be affected, the recovery factor, and all the impact that can cause in the operations, costs, etc. When we talk about water production there are several possible sources associated to this problem, in the literature (Fig.1) there are at least ten know possible sources can cause water production, one of these problems considered is the coning phenomenon (Fig. 2). Eventually, the water or gas breaks through into the well and water from the aquifer and/or gas from the gas cap is produced along with oil. The water or gas production increases progressively after breakthrough time and may reduce significantly the crude oil production. Understand all the parameters that affect or influence coning is very important and also to be able to select the proper methods to analyze and mitigate it. In this paper the water or gas coning is examined covering some analytical methods and numerical reservoir simulation workflow applied to different reservoirs of the Veracruz Basin to understand the behavior of the wells, estimate the critical rates, the breakthrough time and establish a proper plan to this wells to avoid or mitigate the water and gas production; to reach this a numerical simulation workflow is proposed, examples and comparison is included when the wells are above or below critical rates.
Slug Flow Regime and Mitigation Using Transient Simulation, a Complete Workflow
Authors: Villalobos A. , Espinola-Gonzalez O. , Scott-Duran D. W. , Corsi-Regalado C.
Published: June 2016

Severe slugging occurs in different parts of the total production system. Slug flow is a major, expensive headache for oil producers and it has a negative impact on the operation of onshore and offshore facilities. It causes reduction on separator efficiency and unnecessary shutdowns. The study presented in this paper covers the total process to analyze slug flow pattern in a network and possible ways of mitigation.

The oil and gas distribution networks are complex and each present distinct but sometimes overlapping flow assurance challenges that will change over time. In this paper developed a workflow that simulate slug flow. The novelty of this workflow is the ability to perform a slugging analysis with different scenarios that mitigate slug flow. The fluctuations frequently lead to a reduction of separator efficiency caused by excessive liquid levels and pressure surges in the first stage separator. This solution, can provide a relative low-cost method to mitigate slugging and can help the operator to anticipate further decisions based on forecast production, although each system needs to be examined in detail to understand the current operation and the future performance changing the production conditions.
Evaluation of Exploitation Strategies for Gas Reservoirs with Water Influx in the Miocene Formation of the Veracruz Basin Through Numerical Simulation to Optimize the Recovery Factor
Authors: Espinola-Gonzalez O. , Guzman-Arevalo J. D. , Ramirez-Cuacenetl J. R. , Rocha-Carrascal M. , Mehranfar R.
Published: June 2016

Commonly when a conventional gas reservoir is produced always the recovery factor expected is between 80-90%, but when the water appears always the plans are subjected to changes, different considerations and several questions raises regarding how the reservoir will be affected. The most common questions are if the recovery factor will be affected, if the current production strategy will change, if we need to consider critical rates per well, if the plateau will change, reserves, production facilities, etc. The presence of water influx can alter the way the gas is produced by the reservoir as the water invades the gas reservoir, the displacement is not 100% efficient (M.Kelkar, 2008). On the other hand it has long been realized that gas recovery from a water-drive gas reservoir may be poor because of high residual saturations under water drive. The Agarwal study (Agarwal, 1965) showed the quantitative potential importance of water influx; its results indicate that gas recovery may be very low in some cases: perhaps as low as 45 per cent of the initial gas in place. So the important fact is that in gas reservoirs with water influx can change drastically the recovery then the expectations, unfortunately, water influx has forced abandonment of a number of gas reservoirs at extraordinarily high pressures, hence the importance to understand the effect of water in the reservoir based on static and dynamic reservoir parameters, and highlight the importance of gas recovery under water drive appears to depend in an important way on: (1) the production rate and manner of production; (2) the residual gas saturation; (3) aquifer properties; and (4) the volumetric displacement efficiency of water invading the gas reservoir. In certain cases, it appears that gas recovery can be increased significantly by controlling the production rate and manner of production. For this reason, the potential importance of water influx in particular gas reservoirs should be investigated early to permit adequate planning to optimize the gas reserves.

The methodology presented on this paper appraises the evaluation of four different exploitation scheme, trying to understand and determine the best exploitation strategy using a reservoir simulation model applied to two different reservoirs of the Veracruz Basin with different static and dynamic properties, and quantify the benefits to use the proper one to maximize the recovery factor. A detailed description of each reservoir will be review and results will be compared to emphasis that there is no rules to create exploitation plans for gas reservoirs it will depend on several factors.
Case Study: Hibiscus Field 14 Years on - An Integrated Multidisciplinary Approach to Characterize Uncertainty on a Mature Gas Field
Authors: Zimmer Colin , Singh Sidharth , Burrowes Arden
Published: June 2016

The Hibiscus field situated off the North coast of Trinidad is a large, stratigraphically isolated and well-connected gas field which has 14 years of production history. Notwithstanding this extensive production history and overall recovery, a number of key subsurface uncertainties have been identified. The scope of this study was to better understand reservoir complexity and define subsurface risk and opportunity.

An integrated and iterative multidisciplinary approach to reservoir modelling was applied in an effort to meet these objectives. A modern suite of workflows such as Monte Carlo Petrophysical analysis, conditioning of models to seismic attributes, experimental design based uncertainty analysis and assisted history matching were used to generate new static and dynamic reservoir models. The key aspect of this workflow was 20+ major static to dynamic model iterations and a large number of deterministic simulations to rank and asses the validity of static concepts. The learnings were subsequently applied to create a robust reference case, static and dynamic uncertainties framed and a static probabilistic uncertainty workflow developed to QC the deterministic case. A full probabilistic assisted history matching exercise on the dynamic model enabled a refinement of the volumetric ranges and provided critical insight through analysis of posterior uncertainty distributions.

The iterative workflow allowed concepts to be validated dynamically and it was demonstrated that high quality history matches could be achieved even after the removal of almost all dynamic multipliers – a common issue in simulation models. Significant improvements to pore volume distribution, the use of geologically derived dynamic baffles, and permeability distributions were amongst the key learnings on the static side. The probabilistic dynamic modelling was characterized by a strong GIIP convergence with a reduction of history match error, resulting in a refined volumetric range and better characterization of uncertainty ranges through posterior analysis.

The application of modern integrated and iterative workflows to a mature field has better defined uncertainty ranges, understanding of reservoir behavior and overall resulted in a more robust suite of models. Key learnings identified were highlighted to support future reservoir model rebuilds. Ultimately this process has demonstrated the value of revisiting existing datasets in late life assets by generating higher confidence in remaining reserve estimates and business plan forecasts.
Transient Multi-Phase Wellbore Flow Simulation to Accurately Predict End of Well Life and Enhance Recovery
Authors: Solomon S. , Kaasa A. , Singh S. , Pacho D. , Manrakhan S.
Published: June 2016

The field is a Pliocene, shallow-marine, gas reservoir offshore North Trinidad with one producer well and is believed to be supported by a moderate aquifer. In February 2014, formation water production was observed and with near term shut-downs in plan, there was a natural risk of losing the well during a shut-down due to liquid loading. Field remaining reserves were also at risk due to its single well development nature. To optimally manage the well and mitigate these risks, a better understanding of liquid loading and a more accurate end of well life prediction were identified as requisites.

In our experience, reservoir simulation models are unable to accurately predict well life post water breakthrough as they typically use steady state vertical lift performance curves whereas loading, shut-in and start-up operations are inherently transient conditions. Steady state lift curves are derived using nodal analysis and flow regime specific correlations and in case of liquid loading, are valid only for specific liquid film and droplet conditions – which cannot be guaranteed in practice. Thus, a transient multi-phase well flow simulator was used to model with higher accuracy lift performance at higher water cuts and reservoir pressures. This enabled a more robust calculation of liquid hold ups, pressure drops and allowed better prediction of liquid loading. A tuned well model was developed by matching historical data points and a sensitivity study performed using a range of reservoir pressures, chokes, gas rates, water influx volumes and WGRs. Production conditions potentially initiating liquid loading were predicted and were used to identify any near term shut-in periods during which the well could load.

Transient modelling results indicated that the well could die during a shut-in when reservoir pressure dropped below 235 pressure units. Production trend curves were used to forecast these conditions accurately in the near future. A combination of these techniques estimated the end of well life to be any time after Dec 2014, and in reality in Feb 2015 post a shut-down, the well was unable to unload and flow. This closely validated the predictability and robustness of the analysis. By building a better understanding of the high risk periods, more informed well management decisions were made during potential shut-in or choke back periods. This resulted in an extension of the well life and an incremental recovery of c. 2 – 3%.

For gas wells producing water, this is suggested as a robust workflow to closely predict end of well life conditions and timing and hence, support better management of the reservoir and operating conditions during those periods.
Development of a Real-time Decision-Making Dashboard for Drilling Homogeneous Unconventional Shale Plays
Authors: Driver R. P. , Atwal H. S. , Knight S. J.
Published: June 2016

In the current market of drilling programs that emphasise cost effectiveness, making optimum decisions in a dynamic real-time setting is very important. We have observed a disproportional reliance on intuitive decision making in upstream oil & gas operations. In this paper, we propose a process that enables data driven decision making. We then implement this process for a specific situation.

In homogeneous unconventional shale drilling, the number of factors that effect drilling performance are greatly limited. Well drilling times are relatively shorter and so many more wells are drilled in a short period of time. This allows for an opportunity to learn quickly from past wells. We developed a decision-making dashboard that uses data from past wells and helps predict the outcome of a change before it is made. We used multiple linear regression (MLR) as the statistical tool to derive correlations between parameters and drill rate (ROP). Historically, MLR has been used as a tool to optimize the conventional rotary drilling process. However, these analyses are based on limited field data and can yield inaccurate results. The introduction of new drilling technologies such as polycrystalline diamond compact (PDC) bits, rotary steerable systems (RSS), and horizontal well placement have render past models obsolete when applied to modern unconventional homogenous shale wells.

Real-time data were collected from the lateral sections of eight horizontal Marcellus Shale wells drilled from a single pad located in Greene County, Pennsylvania. Twenty-seven variables were identified and evaluated. A MLR of these variables was calculated for each of the eight wells. Weighted averages of the resulting coefficients were then used to derive a predictive ROP model. A decision-making dashboard was created using the coefficients generated through MLR on field data specific to the rig, well-plan, and area being drilled.

In conclusion, a novel method of making data-driven decisions in real-time was developed. This dashboard is especially useful because it formulates a method of extracting actionable information from historical data. Care must be taken to ensure data used for analysis are of good quality and specifically related to real-time applications. These considerations include rig limitations, formation types, well profiles, mud properties. Updating the dashboard with more data as it is gathered enables continued learning from historical well-data in a systematic, data-driven method that has not existed in the past.
Advances in Subsea Separation and Processing Resulting in Discharge of Produced Water at the Seabed
Authors: Prescott N. , Sankar K. , Swenson J.
Published: June 2016

As hydrocarbon fields in production mature, the resultant increase in produced water poses a problem due to the ever-increasing costs associated with handling and separation. Current technology requires produced water to be brought back to a host platform or onshore from offshore reservoirs to address this issue of produced water separation and disposal. Significant interest within industry exists for Subsea Separation Technology, especially where current technology is challenged. The need for new or improved technologies is particularly salient when considering the topic of seabed discharge of produced water. Interest is further magnified in regions such as Trinidad and Tobago, where exploration activities in deepwater blocks have commenced and subsea processing could prove advantageous when compared to topsides.

This paper will discuss the need for development and testing of a subsea produced water treatment system for seabed discharge and the ongoing efforts involved in commercializing this technology. Various existing subsea separation systems will be presented, with reasons why each has failed to render a solution to the issue of disposal of the produced water to the sea. A discussion will be made to illustrate the new era of linear separators, spherical separators, and compact flotation devices that may bring about a technology breakthrough for allowing subsea separation and discharge of the environmentally clean produced water to be discharged at the seabed.

Oil-in-water sensors enabling continuous measurement of produced water discharged at the seabed will also be introduced to illustrate current technology developments. The sensors' design basis and criteria are compared to existing discharge limits in the U.S. Gulf of Mexico and Trinidad and Tobago to highlight the benefits of their use in these regions. In particular, four (4) sensor technologies subject to bench-scale testing in mid-2016 and their working principles are outlined.
Success Story: Short-Term Expenditure Secures Long-Term Revenue in Brownfields
Authors: Patterson Aaronica , Francis-LaCroix Kyethann , Joseph Terry Ann , Sobrien Teri-Ann , Sanchez Alex
Published: June 2016

This paper presents a cost analysis / comparative study of the return on investment realized from the downhole chemical treatment of the Coora CO365 well. The technologies available to permanently outfit older wells that are completed with sub-surface safety valves (SSSVs), with the ability to benefit from direct down-hole chemical remediation, are also detailed.

Producing from a field that was first developed in 1936 and located in southern Trinidad, Coora CO365 experienced paraffin deposition in the near-wellbore and along the well's production string early in its productive life. The operator followed long-term strategic workover plans, but paraffin deposition still continued. Further investigation highlighted that the implementation of an optimal chemical injection program would be critical to realize maximum financial benefit from production of this maturing reservoir.

The operator has been able to replace high-cost workovers with low-cost chemical treatment, significantly improving the economics and prolonging the productive life of this well. Through comparison with older wells (in this block), completed without direct downhole means of chemical remediation, this case will show that simple modifications, though incurring upfront capital cost, can result in long-term revenue generation and early payback, if combined with an appropriate chemical remediation package. The analysis will dispel the common misconception that the cost incurred in refitting older wells with downhole injection capabilities overshadows their revenue generation prospects.

In many cases, the natural decline of a field can be exacerbated by flow-assurance issues in wells and equipment. This paper highlights the potential to sustain production in brownfields that have been plagued with these issues via the use of downhole chemical injection.
The Impact of Reservoir Size on Gas Field Development Options
Authors: Alleyne N. A. , Stoute V.
Published: June 2016

The deep water province of Trinidad and Tobago is the next producing frontier for this country. The area is of interest to a number of major oil and gas companies which have expressed interest in seven of the exploration blocks in the deep water province. An extensive seismic survey was conducted over the area in 2014 and exploration wells are planned for 2016/17. These wells will have to prove up a minimum quantity of resources for the exploration venture to be commercially viable. This paper is an investigation of the minimum resource required to support the development of a gas field in the deep water province of Trinidad and Tobago.

In the absence of published data on the deep water province, analogue data is used to estimate a minimum resource size for commercial exploration by investigating a number of scenarios, which represent the discovery of a total gas- in- place volume of 2 and 3 TCF, with a variety of reservoir sizes and condensate to gas ratios (CGRs), which are typical of those in the existing gas fields of Trinidad and Tobago.

Each reservoir case in the estimated range is used to investigate its own applicable optimum development strategy for taking the gas to market as liquefied natural gas (LNG), compressed natural gas (CNG), gas to solid petrochemicals (GTS), gas to liquids (GTL) and gas to wire (GTW). The paper establishes the total size of the accumulation and the associated reservoir sizes which could lead to commercial exploration in each case.

As exploration moves from the continental shelf into deep water in Trinidad and Tobago, one of the components geologists and geophysicists have specified is required for success in the search for gas reserves is finding larger trapping mechanisms. This paper seeks to estimate some limiting bounds for the designation of a successful find.
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

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

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

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

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

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

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

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

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

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

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 >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.