bluuebunny/crossref_metadata_2025 huggingface dataset:
Conceptualizing an Improved Oil Recovery Master Plan for Trinidad & Tobago
Authors: Sinanan B. , Evans D. , Budri M.
Published: June 2016

Trinidad and Tobago has been an oil producer for over a hundred years. The land based production has historically been the spine of the energy sector. Many changes in reservoir management philosophies, with respect to improved oil recovery techniques (IOR), in the past, can be pegged to economic ramifications, global market issues and technological practicality. What is for certain is that these issues will always have a cyclical presence, but should not be a deterrent in planning the role-out of IOR projects when the market conditions are right. During periods of low oil prices, when capital spending is usually at its lowest, is an opportune time to reassess how to treat with IOR projects. This paper provides an insight into the planning process which can be used as an instigating tool to create an IOR master plan for the land based acreage of Trinidad.

Adding reserves is the ultimate objective but this can be only realized with fit-for-purpose planning and a multidisciplinary coordination of data. The first phase, which this paper addresses, will consider a local historical IOR review, candidate selection with reservoir and technology commentary. These activities would form the basis to drive the first phase action items and spur a second phase of study which would address costs, procurement, execution, KPI monitoring, safety and environment, logistics, risks, contracts, success definitions, approvals, fiscal allowances, technology providers and team building requirements.

Conceptualizing the first phase of a master plan was conducted through data mining, report reviews, interviews and simulation modeling. This paper answers, in brief explanations, the experiences of the past and the methods of the future. Technology identification and application seems to be the principle guide that the reservoir management process needs to consider in developing an IOR master plan for Trinidad's onshore oil fields. An onshore IOR master plan would eventually serve as a manual that strives for an effective and structured manner of exploiting mature fields, regardless of changes in management or management philosophies. The guidance offered within should form the basis or foundation of an eventual master plan.
Effect of Confinement on Gas and Oil Relative Permeability During CO2 Flooding in Tight Oil Reservoirs
Authors: Zhang Kai , Seetahal Steve , Alexander David , Lv Jiateng , Hu Yi , Lu Xueying , Zhang Dingbang , Wu Keliu , Chen Zhangxin
Published: June 2016

For Cardium tight sandstone reservoir and Monteny liquid rich shale reservoir, horizontal well with multi-stage hydraulic fracturing is applied to develop the oil underground. However, Primary recovery of tight oil reservoirs is still low even with horizontal wells and massive hydraulic fracturing. A CO2 flooding process is regarded as a promising technique for improving tight oil recovery. However, the gas-oil relative permeability during CO2 injection is not fully understood because the nanoscale pore confinement in tight oil reservoirs alters phase behavior of the reservoir fluid.

In this paper, the effect of confinement on gas and oil phase behavior is investigated. Afterwards, the gas-oil interfacial tension and solubility parameter are analyzed, resulting in an alteration in relative permeability during CO2 injection without and with hysteresis. Results show that the relative permeability of oil and gas can be further increased by the confinement effect during CO2 flooding as the interfacial tension of gas-oil can be further decreased in a nanoscale pore. Furthermore, miscibility is enhanced by the confinement effect as the solubility parameters difference between oil and gas decreases. It is consistent with the reduction in gas-oil interfacial tension. In addition, the gas phase trapping caused by hysteresis effect is weakened by the confinement effect, resulting in a lower critical gas saturation and a better oil production during CO2 injection.
Impact of the Use of Intelligent Wells on the Evaluation of Oilfield Development and Production Strategy
Authors: Barreto C. E. , Gaspar A. T. , Schiozer D. J.
Published: June 2016

Intelligent wells are widely used around the world and they have the potential to significantly improve oil production or control water production of wells and fields. However, in many cases, the definition of the number and position of valves is still made considering only the well without evaluating if the decision to use them can change other important aspects of the production strategy. This article presents a study to evaluate some relevant aspects of the inclusion of intelligent wells in a more global study of production strategy selection. Such inclusion is an important step in the precise evaluation of the benefits of intelligent valves. The methodology comprises the economic optimization of a production strategy under different limits of platform flow capacity, the optimization of the number and position of valves (intelligent wells), including and excluding conventional well operation. This study was applied to the UNISIM-I-D benchmark case, starting with a previously optimized production strategy, regarding type, number and position of wells, well-opening sequence and platform flow capacity in 9 different geological scenarios. The optimization methodology uses a complex workflow to test different strategy alternatives using a genetic algorithm and a methodology to optimize the number and position of valves. We showed that the use of intelligent wells can significantly alter the water flow capacity and the operational design of wells. However, for this specific case, the use of intelligent wells was not able to modify oil production and water injection flow capacity. Intelligent well application was viable for 7 out of 9 geological scenarios with the number of valves varying from 1 to 14. The intelligent-well application improved the total NPV from 0% to 1.5%. The platform water flow capacity could be reduced by at least 30% if intelligent valves were implemented. These results are quite different when a less precise optimization methodology is applied, yielding an overestimation of an intelligent well. To conclude, the application of intelligent wells was viable for most of the scenarios. Although intelligent wells present low impact on NPV, they can modify the design of platform capacity significantly. This fact suggests that the optimization of intelligent wells must be combined with the optimization of the platform water flow capacity and the conventional well operation optimization. This work provides important information for reservoir engineers who use reservoir simulation to optimize production strategy. Currently, in many cases, intelligent wells are only evaluated after the selection of the platform design. We have proved that the combined optimization can yield a different production strategy design. In addition, we have also proved that the evaluation of intelligent wells viability without an adequate optimization of conventional well operation overestimated the number and the value of valves.
Enhanced Directional Control with Bending Moment and Bending Tool Face Measurements
Authors: Pantin A. K. , Linke C.
Published: June 2016

This paper serves to further develop the method of using bending moment and bending tool face measurements to enhance directional control. The use of these bending measurements to actively steer the drillstring without directional survey information had never before been done in Trinidad, and this paper serves to capture the learnings from this case study. The background and theory of bending moment and bending tool face measurements have already been shown in previous SPE papers as well as their usefulness in providing steering information during casing exits.

The well plan in the case study required a sidetrack off of a cement plug, with the drillstring departing from the original wellbore at 90° right of highside, after which it followed a 3D wellpath before building to horizontal in the target sands. Due to the proximity of the sidetracked wellbore to the original wellbore, directional surveys using MWD tools were not possible for over 350 feet; during this stretch of ‘blind' drilling, the bending measurements were used to estimate survey data. The paper will describe the method in which these estimated surveys were calculated as well as the technique used to verify the bending measurements while running in hole prior to the start of drilling.

A gyroscopic multi-shot tool used to survey the ‘blind' drilling interval confirmed that the bending measurements provided good estimates when compared with the actual survey information. The use of the drilling dynamics tool to facilitate the ‘blind' drilling eliminated several gyroscopic runs, saving time and money for the client.
Improved Oil Recovery for the Complex Fault-Block and Multilayered Reservoir With Edge Water
Authors: Cui R. , Feng Q. , Li Z. , Guo F. , Yan A. , Liu S. , Tao Y. , Chen X.
Published: June 2016

The complex fault-block and multilayered reservoir with edge water, also known as the toothbrush-shaped reservoir, features in multiple oil layers, long narrow oil-bearing belts and the sufficient natural energy. Jin-94 block of Checheng oilfield is a typical toothbrush-shaped reservoir, where upward layer-by-layer production method has been implemented for dozen years. Nowadays, given that 78.2% of water cut and few oil layers that remain undeveloped, the sustainable production for a long term can’t be achieved anymore. However, only 14.2% of the original oil in place (OOIP) has been produced, indicating tremendous potential for the improvement of oil recovery.

The development method plays a dominative and decisive role in recovery efficiency. In order to comprehensively understand the characteristics of the development method, we studied the performance of two alternative methods on the basis of the current development technique in Jin-94. Numerical simulation is applied to production dynamic and comparative analysis of every method. Our simulations show that the optimizing methods exert better effects on oil production, which may serve as an efficient approach to the primary development of other similar fault-block.

To further improve the development performance, the distribution of residual oil in Jin-94 block is also analyzed via numerical simulation. Keeping the current development method of Jin-94 block unchanged, we coupled reservoir simulation with an optimization algorithm to study the capabilities of improved oil recovery (IOR) techniques for this block, i.e., reproduction of obsolete wells, feasibility of water injection, location of new oil wells and optimization of produced fluid intension. Simulation demonstrates that the degree of reserve recovery after optimization increases by over 5%.

This work will not only provide important and specific guidance for the improved oil recovery of the toothbrush-shaped reservoir, but also can improve economic benefits of the oilfield to cope with the challenges of low oil prices.
Real Time Slickline - Applications of New Technology in a Mature Field
Authors: Rivas C. , Bunraj C. D. , Medina A. I. , Araujo J. M. , Padilla A. , Gonzalez G.
Published: June 2016

The Teak, Samaan and Poui fields have been producing oil and gas for over three decades. Over 95% of the wells use gas lift with the remainder producing naturally. In order to address declining production the company conducts yearly rigless interventions to conduct work to remove organic and inorganic scale deposition, gas lift valve malfunctioning and the perforation of unproduced intervals. Throughout its tenure the company has had to take advantage of new and emerging technologies in order to optimize well intervention strategies.

Real time slickline was introduced into the rigless intervention on a trial basis. It was the intent to conduct a technical and cost benefit analysis on the services when used in the offshore operations. This scope of this paper is to present the findings of the trial and to review selected case studies where it has added benefit to the operations.

The real time slickline has been used in the TSP field primarily to conduct production logs (CCL, Pressure and Temperature surveys, Gamma Ray etc.) replacing the traditional memory gauges and convencional slickline unit. This solution has so far allowed the operation to make prompt decisions on well stimulation, gas lift valve change outs and pressure build up surveys while reducing overall logistics cost and intervention time. However, as will be shown, balancing reduced intervention times with the increased cost of the real time slickline versus traditional slickline must be managed in order to gain the full benefit of technology.
New Insights on Relative Permeability and Initial Water Saturation Effects During Low-Salinity Waterflooding for Sandstone Reservoirs
Authors: Shehata A. M. , Kumar H. T. , Nasr-El-Din H. A.
Published: June 2016

Low-salinity waterflooding (LSW) is an enhanced technique that improves oil recovery by lowering and optimizing the salinity of injected water. Previous research demonstrated that the initial water saturation and oil aging during LSW affect oil recovery. This work aims to validate and quantify these effects.

This laboratory study investigated the effect of injected brine, initial water saturation, and crude oil aging on relative permeability and low-salinity waterflooding performance in sandstone reservoirs. A set of comprehensive coreflood tests have been conducted using 3″ Bandera sandstone cores to examine the effect of initial water saturation and injection brine on the relative permeability curves. Additionally, six coreflood experiments were conducted to examine the effect of the connate water salinity variation on the relative permeability end points.

Four spontaneous imbibition experiments were performed using 6 in. length Buff Berea sandstone samples to investigate the effect of initial water saturation and aging on the performance outcome of low-salinity waterflooding. Two spontaneous imbibitions were performed using 20 in. length core samples. The objective of these two experiments was to study the effect of initial water saturation distribution across the core on the oil production using X-ray computed tomography.

Results obtained from coreflood and spontaneous imbibition tests suggest injected brine and initial water saturation have predominant influence on the oil recovery performance. As the initial water saturation increased from 23 to 41%, the oil recovery increased from 43.8 to 48.4% of OOIP using low-salinity waterflooding. Comparison between the high-salinity relative permeability and low-salinity water relative permeability showed that the end-point water relative permeability slightly decreased for the cores after using low-salinity brine as injected brine compared to the end-point water relative permeability after flooding with high-salinity brine for Bandera sandstone. The end-point relative permeability to water increased from 0.07 to 0.39 when the reservoir connate water salinity increased from 4,633 to 174,156 ppm for injected brine salinity of 500 and 5,000 ppm, respectively for Buff Berea sandstone. The un-aged core plugs with higher initial water saturation provided oil recovery higher than that with lower initial water saturation by 5% of OOIP for the low-salinity waterflooding.
Effectiveness of Low-Salinity and CO2 Flooding Hybrid Approaches in Low-Permeability Sandstone Reservoirs
Authors: Kumar H. T. , Shehata A. M. , Nasr-El-Din H. A.
Published: June 2016

Low-salinity waterflooding has been an emerging EOR/IOR technique in the recent times. LSW-alternating-CO2 injection has been particularly strong in yielding higher oil recoveries in some cases. Limited simulation studies haven been performed to properly exhibit the interpretation of experimental studies in this area.

Low permeability sandstones of significant clay content, and heavy west Texas crude oil with 29 °API were targetted for evaluating the potentials of LSWF and CO2 flooding. Coreflood experiments were conducted and interpreted by reservoir simulation, which enabled a better understanding of the underlying science of the studied IOR and EOR techniques. Five secondary waterflooding experiments and two LSW, CO2 hybrid processes were performed using aged 3 in. outcrop grey bandera sandstone cores. The wettability of the rock was tested using axisymmetric contact angle measurements to study the effect of injected brine salinity. The interfacial tension values were measured for the different brines and heavy crude oil systems. The corefloods were interpreted using reservoir simulation, by history matching the experimental oil RF and the pressure drop across the core. A detailed focus was laid on interpretation of SCAL relative permeability curves for the various waterflooding operations, by comparing curves generated from published correlations, history matched curves by simulation and that by Corey's correlations.

Fines migration and viscosity override of low salinity waters over heavy oil were highly influential on the oil recovery profile during low salinity waterflooding. Wettability alteration proved as effective during low salinity waterflooding, for longer injection and production periods. Corey's exponents were found to be premature indications of rock wettability during LSWF, proving importance and reliability of experimental wettability characterization. Low-salinity wateflooding proved to be marginally effective than conventional waterflooding for sandstones with high clay contents and low permeabilities. Low permeability sandstone reservoirs proved as great targets for Hybrid EOR techniques utilizing CO2 and LSW.
Characterization of In-Situ Bio-Surfactant in Microbial Enhanced Oil Recovery
Authors: Hosseininoosheri P. , Lashgari H. , Sepehrnoori K.
Published: June 2016

Capillary force limits the efficiency of water flooding by trapping the oil in porous media. High capillarity is caused by high interfacial tension (IFT) between oil and water that leads to a high residual oil saturation. Surfactants are widely used to reduce IFT and significantly mobilize the entrapped oil. However, the surfactants that are injected into a reservoir to lower the IFT several orders of magnitude may not be cost effective. A cost effective alternative for surfactant flooding is microbial enhanced oil recovery (MEOR). In the MEOR process, nutrients and natural bacteria are injected into a reservoir and both indigenous and injected microorganisms are able to react and then generate biosurfactants based on in-situ reactions.

Modeling a microbial enhanced oil recovery process requires coupling kinetics transport with local equilibrium transport in the presence of the surfactant phase behavior model (i.e. Hand's rule). In general, reservoir simulators do not model relative chemical reactions that consider the effect of essential environmental parameters such as temperature, salinity, and pH.

The main objective of this work is to present first order Monod kinetic equations as a function of temperature, salinity, and pH, which control the biodegradation reactions and microbial growth rate. This involves investigating the impact of biosurfactant adsorption, maximum growth rate, and nutrient concentration. Next, the effects of environmental factors are implemented in a four-phase chemical flooding reservoir simulator (UTCHEM). Finally, the simulator is used to history match coreflood experimental data to model the contribution of the cited parameters on oil recovery.

Results show that in-situ biosurfactant generation rates can be thoroughly modeled based on environmental factors and IFT can be reduced in a similar manner as surfactants. Simulation results show 10-15% incremental oil recovery using in-situ biosurfactant compared to waterflooding. The simulation results show that nutrient concentration, salinity and temperature are the most significant parameters influencing oil recovery, whereas pH has an insignificant effect.

The key findings of this work are the following: In-situ biosurfactant generation in a MEOR process is mathematically described.A new environmental model is implemented into the simulator.Various parameters influencing the efficiency of the MEOR process are investigated.
A Review of Water Reduction Techniques for Open Hole Gravel Pack Completions
Authors: Codrington Kofi , Nancoo-Ali Dana , Leung Daniel , Calvert Patrick , Nouwens Niels , Harris Dayn
Published: June 2016

Water reduction techniques were applied in the openhole gravel pack (OHGP) completions of four wells in Field C. Field C is operated by BP Trinidad and Tobago LLC (bpTT) and is located offshore Trinidad in the Columbus Basin. During the first phase of field development, six wells encountered economically recoverable reserves and first gas was achieved in 2007. The field produced at peak rates from December 2009 to April 2011. Between October 2010 and March 2013, four wells became liquid loaded due to aquifer influx, and production declined by ~ 80%.

The second phase of field development was scheduled to commence in 2016, and hence the bpTT field team began to investigate ways to revive the four liquid loaded wells and return them to production. Using experiences from BP Global Operations, and based on the assumption that the reservoir drive mechanism was bottom and/or edge water drive, the team decided to install zonal isolation devices. Also known as water shut off plugs; these devices are usually used in oil well casing applications and had never before been tested in gas well openhole gravel packs in Trinidad and Tobago. Each plug was set within an interbedded shale in the reservoir and screen joint of the completion to provide a vertical flow barrier. Due to uncertainty on the lateral extent of the shale and its ability to act as a barrier to water encroachment, an additional step of dynamic wellbore modelling was implemented. This was used to modify well bean up in order to minimize drawdown while maintaining the critical rate.

The well intervention campaign to install the plugs began in December 2013 and was executed using both slickline and e-line tools. One of the key considerations during job execution was depth control, to prevent setting the plugs too high in the wellbore and isolating gas bearing sands. This was achieved by correlating the gamma ray (GR) and Casing Collar Locator (CCL) logs with the original openhole logs. The plugs were installed by July 2014 and 75% of the wells were successfully offloaded with an average reduced WGR of 40%. This prolonged the producing life of the wells and improved the recovery factor by an average of 2%.
An Integrated Method to Characterize Shale Gas Reservoir Performance
Authors: Zhan J. , Seetahal S. , Cao J. , Hejazi H. , Alexander D. , He R. , Zhang K. , Chen Z.
Published: June 2016

The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations. However, due to the complexity of fracture network propagation, simulation of such reservoirs is challenging and associated with uncertainties. In order to minimize the uncertainty of modeling, we correlate first-hand pumping schedule data with the reservoir performance directly through coupling a fracking process with a reservoir simulator. This provides us an integrated way to characterize a well trajectory, hydraulic fracture configurations and shale gas reservoir performance. In addition, a geomechanical effect on the reservoir performance under certain fracture configurations is studied using a geomechanics module developed by CMG Ltd.

GOHFER is widely used in a hydraulic fracking analysis. In this work, we couple GOHFER simulation output with the CMG module to determine the hydraulic fracture configuration. Thus, a method to correlate the first-hand pumping data (a slurry rate, slurry concentration and pumping pressure) with the reservoir simulator is given. Because of the stress sensitivity of a shale formation, we employ a linear-elastic constitutive law to depict the rock behavior with Young's modulus of 5,000,000 psi and Poisson's ratio of 0.2. Moreover, a Barton-Bandis model is used to describe the tensile opening of natural fractures for the dual-permeability reservoir model.

From a series of numerical simulation studies, we find that the effective normal stress will increase with the development of a shale gas reservoir which will lead to a decrease in porosity and permeability. For the base case without a geomechanics effect, it will produce higher cumulative gas production than the case with the geomechanics effect. When producing for six months, the difference of the cumulative gas production between the two cases is 14.3%. The integrated process provides insights about shale gas reservoir performance with available data and handy tools.
Characterization of Hydraulically-Induced Fracture Initial Water Saturation Distribution Using Arp's Correlation
Authors: Zhan J. , Seetahal S. , Alexander D. , Hejazi H. , Paul Cao J. , He R. , Zhang K. , Chen Z.
Published: June 2016

The application of coupled horizontal wells and the multistage fracturing technology to shale formations makes it viable to develop such hydrocarbon resources. In this paper, we focus on the water saturation distribution within hydraulic fractures and the uncertainty of water saturation distribution of the matrix around the hydraulic fractures resulted from fluid injection during a fracking process.

Arp's decline curve is introduced to depict initial water saturation distribution within the hydraulic fractures. Through modifying the decline index, it is easy to obtain a range of initial water saturation decline patterns which will lead to different water production profiles. Typical decline patterns such as linear, exponential, harmonic, and hyperbolic declines are used. As for the initial water saturation distribution of the matrix around the hydraulic fractures, the Stimulated Reservoir Volume (SRV) concept is implemented to identify the matrix region.

Through reservoir simulations, we find that the initial water saturation within the hydraulic fractures mainly contributes to the early water production. Various saturation distribution models result in about 25% differences in the total water production. On the other hand, a leak-off effect, which increases the initial water saturation of the matrix around the hydraulic fractures, contributes to the long term water production. This study provides insights about the uncertainty of water production during the development of shale gas reservoirs and guidelines for the history matching of water production rates.
Unearthing the Impact of the Geology of Aquifer Systems and Its Effect on Hydrocarbon Recovery in Gas Reservoirs in the Columbus Basin
Authors: Roopa Iannie , Rastogi Vandena , Dickey Doug , Baksh Kirk
Published: June 2016

Aquifer strength has a significant impact on recovery largely due to subsurface uncertainty in the aquifer connectivity and aquifer size. A wide range in recovery has been documented in the literature and has been similarly observed in gas reservoirs in the Columbus Basin (Trinidad) by comparing reservoirs with similar initial and platform pressures. Consequently, understanding aquifer systems can influence development strategies and economics. An example of this is in facilities design where stronger aquifers should have pipelines sized for large volumes of water post water breakthrough while the more volumetric fields should cater for lower pressures via compressors or eductors.

Uncertainties in aquifer support and gas-in-place estimates often introduce uncertainty in production forecasts. Dynamic data for some gas reservoirs reveal that aquifer pressure support strength varies between gas fields and also for individual reservoirs within some fields. This dynamic data includes the integration of surveillance data such as pressure transient derivative and saturation log time lapse data with material balance calculations. Typically the understanding of the geology of aquifers is limited to aquifer size, permeability, edge versus bottom water drive and high permeability streaks.

This paper collates a new combined dynamic and static analysis on a number of BP Trinidad and Tobago LLC mature reservoirs in the Columbus Basin that have been categorized from volumetric to strong aquifer behavior. This integrated view improves the overall understanding of how geology contributes to aquifer impact and helps to create integrated subsurface scenarios that characterize each aquifer system and enable better predictive capability in future developments.
Asset Integrity Management and Life Extension of Gas Distribution Facilities and Pipeline Network
Authors: Nezamian A. , Rodriques C. , Nezamian M.
Published: June 2016

Gas processing facilities and pipeline networks play a key role in energy distribution. There is an ever increasing need to extend the life of the aging networks beyond their original design life and operators are continually looking for requalification and extension of the service life aimed at ensuring the integrity, functionality and availability of the network for the extended operating life. In order to ensure technical and operational integrity of this ageing infrastructure, the fitness for service of these systems is required be maintained for the intended service life.

Maximising the availability and functionality of the network, whilst operating safely and with minimal impact on the environment, is a major concern for requalification and life extension. Gas processing asset integrity management (AIM) and pipeline integrity management (PIM) consist of inspection, testing, maintenance and repair programs are critical to ensure integrity and sustainability in gas production. The AIM program is to assess and report upon the risks imposed on the community by natural gas supply facilities, and based on the available information; identify opportunities for improvements to ensure the risks to the community are as low as reasonably as practicable (ALARP) (UPSTREAM NATURAL GAS SAFETY REPORT 2001). Detailed integrity assessments are needed to demonstrate that there is sufficient technical, operational and organisational integrity to continue safe operation throughout an extended service life. Information on characteristic data, condition data, historical performance, maintenance management and inspection and testing results are required to assess the current state and to predict the future state of the network subsystems and critical components and the possible extension of service life. Effective record keeping and ongoing analysis of data are key inputs to a successful life extension program (Nezamian and Altmann 2013).

This paper presents state of art practices in life extension of existing gas distribution and pipeline facilities and an overview of a customised life extension methodology to address risk factors to the integrity of a gas distributio and associated facilities. It covers the required procedures and re-assessment criteria for a life cycle cost effective approach to decide on life extension in particular the one with the importance such critical subsystems.
Zero Offset VSP in a Deviated Well and Q Factor Estimation
Authors: Oriach N. , Gallai-Ragobar N. , Romero J. , Archie C. L. , Ramdin K.
Published: June 2016

Vertical Seismic Profiling (VSP) is a technique in geophysical exploration, which involves recording downgoing and upgoing wavefields propagating through the stratigraphic section. In a Zero Offset VSP the receivers are located in the wellbore, allowing the wavefront produced by the source to have a shorter path to reach them. As a primary consequence of that, there is less attenuation of of high frequencies, which means better resolution. A Time – Depth relationship and a corridor stack are generated in to correlate with surface seismic at 1D response (i.e. well seismic tie). However, a rig-source VSP survey acquired taken on deviated wells can also provide a 2D image below the wellbore trajectory.

A rig-source VSP was conducted on a deviated well in a field located in the Gulf of Paria, Trinidad and Tobago. Three (3) component data was recorded and 3-C processing was used to obtain a corridor stack as well as a 2D image. This information is to assist in the reservoir delineation and characterization, as well as in the development of a velocity model for ongoing 3D seismic processing in this field.

This 2D image has a frequency content of approximately about 90Hz, which showed higher frequencies in comparison to surface seismic acquired in 2005. The correlation of the image with the seismic section was excellent, illustrating deep structural features with better resolution than seen on surface seismic. In addition, Q absorption values using spectral and multi-spectral methods were calculated, resulting in values of 63.00 and 62.85 respectively. This was interpreted as medium values of absorption for these formations. The Q values are presently being used to balance amplitudes in an ongoing 3D seismic processing project.

This example confirmed the importance of the VSP as an excellent tool for calibration, interpretation and processing of seismic data that will ensure more accurate planning and placement of new wells.
Quantifying The Value Of Seismic Re-Processing And Inversion: A Case Study From Block 22 And NCMA-4, Offshore Tobago
Authors: Nagassar V. T. , Moonan X. , Kimber R.
Published: June 2016

Determining whether a seismic re-processing and inversion project has delivered its technical objectives is fairly straightforward. A comparison and analysis of the structural and stratigraphic imaging, reflector continuity, bandwidth, noise content and synthetic well ties can all be used to determine technical success. It is sometimes more difficult, however, to quantify the value derived from the new seismic products. The value proposition is particularly relevant when seeking approval for future re-processing projects especially in the current difficult economic climate. We present an example from offshore Trinidad where the value of a seismic reprocessing and inversion project have been quantified by reviewing the impact decisions made as a direct result of the new data has had on the cost and Net Present Value of the project.

The Cassra and Iris fields are Pliocene and Pleistocene aged gas sands deposited in a shallow marine environment and basin floor setting respectively and are located 15-20km off the north coast of Tobago. Both fields are covered by 3D seismic data and are currently in the pre-development project phase. A post migration gather conditioning and inversion project has recently been completed over both fields with the primary objective of improving the pre-stack data and subsequent inversion products for reservoir characterization, dynamic simulation and development well planning. A full re-interpretation on the new data is ongoing but initial observations have already dramatically influenced field development decisions.

Detailed mapping of the reservoir on improved resolution data allows for a confident assessment of reservoir architecture, mapping of individual sedimentary clinoforms and determining the areal extent of individual sand bodies. This has changed our views on the risk of reservoir compartmentalization and when integrated with other data types have influenced the development concept and well count required to develop these fields. A seismically derived net pay estimate on both fields has also influenced project volumes and an assessment of the Net Present Value (NPV) impact of the volume change has also been used to quantify the value of the new data.

The financial impact of the new data as a result of changes to the field development plan may be either positive or negative in terms of overall development cost, but provides an indication of the true value of the data. This is based on the premise that if the new data merely confirms the existing interpretation and has not impacted any business decisions, then no additional value has truly been achieved.

Specifically, we aim to answer the question most managers will pose…‥"You have spent a lot of time, money and effort on this project and delivered some imaging improvements, but what value has it brought and why should I spend any more money on another project?" We hope to answer that question!
Unlocking the Potential of the Basal Sands, Paria Sub-Basin, Trinidad and Tobago
Authors: Moonan X. , Kimber R. , Nagassar V. T.
Published: June 2016

In 1971, the Bluewater III semi-submersible rig drilled the first wildcat well, KK6-1, some 40km north west of Tobago's Buccoo Reef, in the Paria Sub-Basin of the North Coast Marine Area, resulting in the Orchid discovery. The subsequent appraisal well, KK6-2 discovered gas in a series of stacked Late Miocene (NC30) – Pliocene (NC80) sandstones. The lowermost and thickest of these gas charged sandstones was found unconformably overlying Cretaceous metamorphic basement, and has since been termed the Basal Sand.

In 2011 a 4370sqkm 3D seismic survey was jointly acquired over NCMA and Block-22 by Niko Resources and Centrica Energy, allowing for extensive regional mapping and the potential to resolve the Orchid Basal Sand gas discovery. Detailed mapping on basement revealed extensive areas with pronounced dendritic drainage, potential islands and shelfal platforms. Seismic amplitude extractions at this interval point to a number of low impedance anomalies, one of which ties very well to the KK6-2 gas discovery.

In the absence of Basal Sand core at Orchid, present day analogues were selected for reservoir sampling and analysis. Integration of regional well data, sea bed samples, ocean current data, seismic impedance volumes, thin sections from side wall cores and cuttings as well as palinspastic restorations resulted in the generation of a regional NC30 Basal Sand gross depositional map, depicting the drowned mountain ridge of ‘Isla de la Asumpción', carbonate mounds and potential Orchid Basal Sand look-alike plays within the Paria Sub-Basin.
An Integrated Reservoir Analysis to Evaluate Water Flooding and Define Remaining Potential of the Teak Field, Trinidad & Tobago
Authors: Atienza Juan , Vitarella Laura , Segnini Carlos , Singh Anjani Kumar , Alkatiri Fauzi , Oviedo Javier , Vela Rafael
Published: June 2016

Teak, Samaan and Poui (TSP) are mature fields off the South-East coast of Trinidad, which currently produce near to 14,000 bopd with an average Water Cut of 85%. Their production started in 1972 and peaked at 143,300 bopd in 1978.

The 0/1L Sand, in the Teak field, has accumulated over 72 MMBO and displays a low reservoir pressure, yet it still contributes with almost 10% of the total current production of TSP. Secondary recovery was implemented in TSP since the late 1970s; some 21 MMBO are estimated to have been recovered from Sand 0/1L, in the Teak Field, thanks to the Water Flooding campaign, which was active between 1977 and 1998.

Repsol E&P T&T ltd., operator of the TSP asset, has identified the potential for increased oil recovery by means of waterflooding. Evaluating injectivity of those wells that are available for injection is the starting point of the current strategy. Additionally, Repsol's Technology Center in Madrid has been contacted to perform a specialized water characterization and compatibility analysis, which is currently ongoing. The focus of this paper however is the subsurface.

Initially, the reservoir pressure and production behaviour has been analysed to estimate pressures and analyse block connectivity. Together with this a first one-dimensional material balance model was created to preliminarily evaluate performance. A multi-layer Water Flood pattern simulator, which has proven very useful in understanding past performance, was one of the main tools of the analysis. Finally, a full 3D model is currently being tuned to obtain definite production profiles. Furthermore, the value of detail model preparation was proven by the identification of potential workover candidates. Remaining oil was identified in bypassed areas and in zones previously interpreted as gas bearing.

The main goal of this paper is to understand past performance of waterflooding as the key to defining the remaining potential.
An Alternative Workflow to Calculate Permeability from the Resistivity Logs and Improve the Flow Unit Definition in the Teak Field, Trinidad & Tobago.
Authors: Vitarella Laura , Atienza Juan , Meduri Giovanni , Vela Rafael
Published: June 2016

Teak, Samaan and Poui (TSP) is a mature field off the South-East coast of Trinidad, which currently produces near to 14,000 bopd with an average Water Cut of 85%. In production since 1972, it peaked at 143,300 bopd in 1978.

Repsol E&P T&T has been looking to increase oil recovery by unlocking the remaninig potencial of their reservoirs in Sands 01, 02, 1/2 and 2. An interdisciplinary and detailed study was generated between several disciplines, including geology, petrophysics and reservoir engineering, to re-evaluate these sands, where a waterflooding project had been implemented between the 70's and 90's with seemingly good results.

A Static Model was generated starting from a detailed well by well analysis (well logs and core information, seismic, production and pressure data, etc…), where some problems, related to uncertantly in the Structural Model and to the interpretation of the input data had to be overcome. This paper explains the workflow that was used to create this static model.

First, the originally suspected several Oil Water Contacts (OWCs) had to be analyzed. The area is affected by several fault blocks with varying juxtaposition of the geological layers, which lead to the interpretation, in previous studies, of several contacts. A solution to this and to the effect that this juxtaposition has in the flow within the reservoir and in the pressure distribution is analyzed in this paper.

The next step was to reach to a rock type definition based on k/phi relations and a J Function (J(Sw)), with the challenge of having insufficient Core Data and Pc curves. An additional challenge faced was the questionable resistivity logs, which are suspected to have been affected by drilling mud throughout the successive drilling campaigns.

Then, in order to define permeability and water saturation models, an alternative workflow was tested and implemented. This method includes conventional rock typing analysis (Pc derived J(Sw)) and extrapolation of these results to the wells. This, together with the resistivity logs (Sw), has been used to compute permeability above the OWC. Threrefore, this allows us to calculate permeability first, and then use it in the J function to calculate the water saturation that will be input into the model.

Finally, a Lorenz plot was built to define flow units and identify the possible water injection paths.
Comparing the Feasibility of Two CO2 EOR Processes: Continuous vs W.A.G Injection on A Field Onshore Trinidad
Authors: Hernandez J. J. , Julien G. , Noel L. , Alexander D. , Seetahal S.
Published: June 2016

Two Enhanced Oil Recovery (EOR) methods were analyzed for producing hydrocarbons from a newly discovered JLG field using analogous information from a reservoir of similar geologic characteristics as those in southern part of Trinidad. Continuous CO2 injection and water alternating gas (WAG) were modelled after primary recovery using CMG-GEM. The feasibility of these processes were determined using the overall cumulative production and CO2 storage capacities. Injection time for each EOR strategy was simulated for a ten-year period. The comparisons were done using various hydrocarbon pore volumes (HCPV), injection times, WAG cycles and WAG ratios to analyze the production curves and the amount of sequestered CO2.

The results showed that reservoir had an 18.2% recovery factor (OOIP was 29,750 MSTB) from primary production. From the models developed, immiscible continuous CO2 injection was the most feasible EOR process coupled with sequestered. This model produced the highest incremental oil recovery of 26.3%, which corresponded to a cumulative oil production of 13,286 MSTB (44.66% recovery). A total of 284.11 MMSCF (14992.6 metric tons) of CO2 (16% storage) was also stored. Hence, an immiscible continuous injection process can be more economically feasible since it requires a smaller volume of CO2 and produces a greater volume of hydrocarbons for similar type fields. This is further supported by the feasibility analysis, which showed that the continuous CO2 immiscible injection process would produce a net present value (NPV) of US$ 355M, with an internal rate of return (IRR) of 83.9%.
Foreign Trade-Foreign Exchange Nexus in Nigeria: A Vector Error Correction Modelling Approach
Authors: Awe Olushina Olawale , Akinlana Damola M. , Adesunkanmi Sherifat Omolola
Published: June 2016

This study investigates trade foreign exchange nexus in Nigeria. This study is also done with a view to detecting the kind of relationship that exists between the two and also to investigate their co-integration. Annual time series data for the period 1996 – 2010 was used for the study. The Vector Correction Model (VECM) approach was employed to determine both the short and long run relationships. Results showed that the series becomes stationary after second difference. The co – integration test reveals five co – integrating vectors in the model, implying that the variables have the same stochastic drift. The study concludes that a long-term relationship exists between foreign trade and exchange rates implying that foreign trade flows have a strong link with exchange rates in Nigeria.
PENGEMBANGAN POTENSI PESANTREN DALAM MENCETAK SANTRIPRENEUR (Pemberdayaan dan Pendampingan Santripreneur di Pesantren Manahijul Huda Ngagel Dukuhseti Pati)
Authors: Saifullah Muhammad , Royyani Muh. Arif , Shobaruddin Muhammad
Published: June 2016

Pondok Pesantren memiliki peranan penting di masyarakat, khususnya terkait persoalan agama. Saat ini, di tengah perkembangan zaman alumni pondok pesantren dituntut tidak hanya mahir dalam hal keagamaan saja, melainkan juga hal lain salah satunya adalah ekonomi. Pondok Pesantren Manahijul Huda sebagai pondok pesantren yang telah lama eksis di tengah-tengah masyarakat Desa Ngagel Kecamatan Dukuhseti Kabupaten Pati memiliki banyak alumni yang dinantikan kiprahnya di masyarakat. Sebagai upaya untuk memberdayakan para alumnus Pondok Pesantren Manahijul Huda khususnya di bidang ekonomi, maka tim KPD LP2M UIN Walisongo Semarang mendirikan sebuah konveksi penjahitan baju. Di kecamatan Dukuhseti terdapat beberapa lembaga pendidikan yang terdiri dari 3 Madrasah Aliyah, 3 SMK, 6 Madrasah Tsanawiyah, dan 8 Madrasah Ibtidaiyyah, yang memiliki total siswa sekitar 4.000 orang. Selama ini sekolah-sekolah tersebut saat hendak membuat seragam sekolah (Batik, Pramuka, Kaos Olahraga dll) untuk para siswa, selalu pergi jauh ke kecamatan lain, bahkan ada yang ke luar kabupaten Pati. Peluang inilah yang dilihat oleh Tim KPD LP2M UIN Walisongo untuk mendirikan usaha konveksi sebagai upaya untuk memberdayakan alumni sekaligus membantu sekolah-sekolah di kecamatan Dukuhseti dalam menjahitkan seragam para siswanya