bluuebunny/crossref_metadata_2025_split huggingface dataset:
Trinidad and Tobago's Current Deepwater Campaign: Implications of the Contractual Obligations and Taxation Regime
Authors: Razack J. 
Published: June 2016

Abstract
Trinidad and Tobago is exploring 9 frontier blocks in water depths 1800 to 2200m. 3D seismic was completed in 2015 and the first well is to be spudded by mid-2016. As per the contracts, a minimum of 8 exploration wells are to be drilled. This paper aims to determine how small an oil or gas field could be and still generate economic rent.
The taxation system and contractual obligations for two blocks were used to model oil fields of reserves 150 and 300 mmbbl and gas fields of reserves 2400 and 4800 Bcf. The production rates and oil/gas prices were varied to determine their impacts on investment criteria like NPV, IRR, payback time and government take. The models were used to project the minimum field sizes at different oil and gas prices that would be commercial.
At $60/bbl, the minimum economic size for a standalone oil field is approximately 300 mmbbl reserves. Economic means that the field must attain a positive after tax NPV @10%. None of the gas models were economic at $3/mcf. It was projected that at this price, a single field with at least 12 Tcf reserves must be discovered to be commercially viable.
Further, the minimum obligatory spend on the 9 blocks is approximately $765M in 2012 dollars. To breakeven with this expenditure, (that is, post-tax NPV = $765M) the largest field modelled (300 mmbbl) requires an oil price of $100/bbl.
First tax revenues are forecasted as 2026 for oil and 2029 for gas. The first PSCs were executed in 2012, so first production is modelled 14 to 17 years later. Government take ranges 55 – 60%. While the PSC mechanism of taking taxes out of the government’s share reflects long term stability from the investor’s point of view, changing individual tax rates may be irrelevant as the full taxes owed are never paid over the field life.
These models are dependent on a myriad of assumptions. Variations in reservoir characteristics, new technology, market availability and global prices can have dramatic effects on the results.
The deepwater is widely considered to be the last frontier for T&T’s hydrocarbon industry. Therefore, it is critical that we understand how the contracts and taxation regime affect the commerciality of any potential fields, and make any necessary changes.
Mature Field Rejuvenation by Reactivation of Idle wells in Petrotrin's Land Acreage
Authors: Batohie G. 
Published: June 2016

Abstract
In 2011 January, the Petroleum Company of Trinidad and Tobago (Petrotrin) embarked on an initiative to rejuvenate its mature land fields by using different intervention strategies to monetize the remaining reserves in its inventory of idle wells. This exercise included but was not limited to annexation of idle wells to Lease Operators and a reactivation exercise seeking to generate oil production from a total of one thousand, seven hundred and twenty six (1726) inactive wells, which included three hundred (300) inactive wells that were in close proximity to the active lease operatorship blocks and were earmarked for lease out. This paper presents results from the reactivation exercise.
The candidates reviewed for reactivation were in mostly shallow, unconsolidated reservoirs, onshore Trinidad. Most of Trinidad's onshore crude oil producing reservoirs is considered to be mature which means that the oil reserves would have been, or are still being, produced by primary means, with Enhanced Oil Recovery (EOR) methods being used in some reservoirs. With declining oil production being experienced currently, there is the need to find alternative ways of arresting the declining production trend. One method of doing this is by tapping into the proven, idle reserves from wells that may have been taken off production due to low production rates and unfavorable economics at the time. Identification and reactivation of candidates is therefore important in helping to realize the full potential of mature producing fields such as those onshore Trinidad and to recover potentially bypassed pay. The reactivation project applies current technologies for identifying and unlocking potential in inactive wells.
A total of one thousand and seven hundred (1700) wells were screened as candidates for the Land Reactivation Project as at September, 2014. This paper reports on the performance of the wells reactivated for the period of January, 2011 to September, 2014, a period of approximately four fiscal years. This phase of review and evaluation was termed Phase Four (4) of the Reactivation Project and it forms the basis of this paper.
The total number of wells reactivated during this period was two hundred and seventy six (276), with a total of one hundred and ninety two (192) wells maintaining active status and eighty four (84) wells inactive at September, 2014. This equates to an overall project success rate of seventy percent (70%). Approximately fourteen million dollars ($TT 14million) profit, for fiscal year 2013-2014 was realized. These results prove that reactivations are an economically attractive venture.
Due to fallen oil prices at this time, exploration and production of new reserves to boost declining oil production may not be economically attractive and reactivation of idle wells may prove to be a more feasible option in some instances.
Application of a Steam Assisted Gravity Drainage Model to Deviated Wells in a Dipping Heavy Oil Reservoir
Authors: Ramasray K. , Sobers L. E. 
Published: June 2016

Abstract

Objectives/Scope
The Butler Analytical model has been used to predict steam flood performance using Steam Assisted Gravity Drainage (SAGD). In this paper we apply the Butler Analytical model to three pairs of deviated wells in a steeply dipping heavy oil reservoir.

Methods, Procedures, Process
Simulation studies were carried out on a 100ft thick heavy oil sand with 12 degree API crude for three pairs of parallel deviated wells in a dipping reservoir, situated perpendicular to the 40 degree incline of the reservoir. The results of the simulations study were compared to the production profile predicted by the Butler Analytical Model.

Results, Observations, Conclusions
Both the simulation results and the Butler Analytical Model predict a production profile with two production peaks. The results of the three pairs of parallel deviated wells show the effect of dip and well placement on oil recovery (average 53%) and water production. The major factors influencing the formation of the steam chamber and oil production are reservoir heterogeneity, steam override and well placement. Overall, cumulative production values obtained from the Butler analytical model were less than those from the simulation but the production profiles were comparable. The main difference is due to the advantage of optimal well placement which the Butler analytical model does not take into account. Our results show that the downdip positioning of wells increased oil production. The results of this study are then more closely aligned with the findings of Ramjohn (2014) than Andarcia et al (2014), which concluded that SAGD, (modified for dipping reservoirs), can be effective with optimal well positioning.

Novel/Additive Information
The work presented in this study shows that the Butler Model can be used to predict steamflood performance in deviated wells to recover heavy oil from dipping reservoirs.
Offshore Economic Field Development Concept - Step Change
Authors: Prescott C. N. , Paramsook S. , Mohammed W. , Mejia F. 
Published: June 2016

Abstract
Oil prices have fallen dramatically to the average range of USD $30 to $50 per barrel and are expected to stay in this average range through 2017 or beyond. Field development costs for deepwater have fallen but are still a major obstacle to efficient field development and this is not expected to change in the foreseeable future. A failure to adapt to this new economic reality could seriously impact the industry. New strategies and concepts are needed to ensure a sustainable deepwater industry, especially for the more challenging reserves. This presentation will discuss a step change solution to providing a field development concept that will be economic in today's conditions.
New strategies and concepts for deepwater field development will be discussed for a cost-challenged environment. Partnering and development strategies will be defined, as these will facilitate subsea development of the most challenged assets and could reduce project cost by up to 30% and to shorten project schedule by 18 months to 2 years.
This paper will discuss the following: Development strategies to go forward for a cost-challenged deepwater businessNew development concepts for field development, including processes and equipment beyond Jules Verne conceptNew partnership models to allow for economic provision of resources: utilities, water, etc.Standardization recommendations.
Major changes are needed to empower the move to an economic field development concept and these will be discussed with details showing the future of deepwater development.
Quantification of Simulation Model Grid Size Impact on Polymer Flooding Application in Heavy Oil Heterogeneous Reservoir
Authors: Rego F. B. , Botechia V. E. , Correia M. G. , Schiozer D. J. 
Published: June 2016

Abstract
Polymer flooding can be a viable alternative to enhance oil recovery of heavy oil fields. The comparison of water and polymer flooding requires a reliable reservoir numerical model to safely ensure the decision analysis including uncertainties and involving a significant amount of simulation runs. Reservoir engineers usually work-around this problem using fast models to reduce computational time; however, it is important to maintain the reliability of heterogeneous reservoir models. Therefore, the proposed work demonstrates how the grid size impacts on accuracy of results and both the time and computational resources. In addition, it is performed an analysis to establish how the typical physical phenomena related to the polymer flooding impact the applicability of the proposed methodology.
A highly heterogeneous heavy oil field is used in our proposed studies. The application is conducted to assist pilot test wells. Initially, the definition of the reference strategy (OTM) is presented. In this case study, the OTM strategy is based on the optimization of location and number of wells. Secondly, the effect of grid size on the process is evaluated through two procedures: (1) DA method: a selection of grid size defined by drainage area of the selected wells; and (2) UP method: upscaling is performed in the simulation model. Then, production parameters resulting from models of both procedures (DA and UP) are compared with OTM results. The definition of which procedure is better to represent the wells of interest is performed. Finally, the impact of three polymer flooding physical phenomena (degradation, adsorption and Non-Newtonian effect) on production results is presented, in order to verify the accuracy of the generated fast models in maintained considering these effects.
The DA method present good accuracy for reservoir response compared to the reference OTM results. Differently, UP models are not as accurate as DA models for production results indicators. In conclusion, the application of the methodology allows choosing the DA over the UP technique to support our decision in the investigated recovery methods, showing a reliable and fast procedure. Finally, this procedure shows excellent applicability and robustness when a typical polymer flooding study is carried out: the evaluation of physical phenomena impact on production results based on wells of interest.
The Experience of Using Jet Pumps with Hydraulic Pumping Bottom-Hole Assemblies to Reactivate Idle Wells in a Heavy Oil Reservoir in the East Soldado Field
Authors: Mohammed Shazim K. 
Published: June 2016

Abstract
This paper presents the performance and compatibility of using jet pumps with hydraulic pumping bottom-hole assemblies that were designed to work with hydraulic piston pumps in an attempt to reactivate idle wells in a heavy oil reservoir, offshore South-West Trinidad. The resilience of the already installed hydraulic bottom-hole assemblies made it easier to select jet pump as the artificial lift method for reactivation.
Jet pumps were designed with dimensions to fit in the hydraulic bottom-hole assemblies. Assemblies were modified by using a 13 ft length of 2" pipe inside them to ensure that the seals in the pumps and the polished sections of the assemblies meet at the same depth. The production string from the triple string completion was isolated since only 2 completion strings were required for operation, leaving the power oil injection and fluid return strings active. Jet pumps were installed on 4 wells. Performance was monitored using sonologs to determine fluid levels and clamp-on ultrasonic flowmeters to determine injection and production rates.
Results showed that drawdown was occurring and production was obtained from all 4 wells during the first 4 months of operation since submergences were lower than the static levels. After this period, the submergences of 3 wells increased to the static levels and test rates showed that these wells were not producing. The submergence of the 4th well was fluctuating and tested 76 bpd. On inspection, it was discovered that the throats and nozzles of the other 3 wells were plugged with seal fragments from the surface power oil pumps. The jet pumps were cleaned and reinstalled after which the submergences dropped drastically within the first month of returning to operation. From these results, it can be concluded that the jet pumps are compatible with the modified hydraulic pumping bottom-hole assemblies. All 4 idle wells completed in this heavy oil reservoir were successfully reactivated however the performance was affected by plugged nozzles and throats of the jet pumps by seal fragments from the surface power oil pumps. Submergences could be reduced to optimize all 4 wells by changing the nozzle and throat sizes to achieve optimum performance and production rates with the maximum power oil injection pressure of 2400 psi.
This paper describes the experience of using jet pumps in the East Soldado field to reactivate heavy oil wells by making minor modifications to the existing hydraulic bottom-hole completion that was designed to be used with hydraulic piston pumps. The use of jet pumps was motivated by the need to reduce workover and operating costs together with the demand to increase oil production. This modification was successful based on the production and monitoring parameters obtained.
Experience with Progressive Cavity Pumps in the Soldado Field, Offshore Trinidad
Authors: Garcia-James C. J. 
Published: June 2016

Abstract
The use of progressive cavity pumps (PCP) in the offshore assets (Soldado Field) of the Petroleum Company of Trinidad and Tobago Limited (Petrotrin) began with pilot projects in early 2000, however full adoption of this artificial lift system occurred from 2003-2005. Almost a decade after and due to a reduction of run life of the pumps and the increase in workover frequency, a complete review of the PCP system was done in order to identify type and causes of failures, present best practice solutions to reduce premature failures and recommendations for optimum design and operation. This paper discusses the results of the review and the steps being implemented by Petrotrin Trinmar Operations towards the management of PCP during the productive life of an oilfield.
The initial approach was the visit of Subject Matter Experts (SME) to Petrotrin Trinmar Operations to consult with production engineers and field operators on the problems experienced. Detailed evaluations were performed on the type of failures and their location in the PCP system. Destructive and non-destructive test were done on selected rods, pumps and accessories. Supervision during the running of sucker rods into producing wells to ensure the proper installation of the systems. Revision of the processes and participants in the management of Artificial Lift Systems (ALS) i.e. identification of candidates wells for PCP, design and procurement of these systems, installation and pulling, monitoring and maintenance. The process was completed with the establishment of Key Performance Indicators (KPI) to assist in decision making regarding the performance of PCP.
The results indicated that the run lives of most PCP systems in Petrotrin Trinmar Operations were similar and sometimes above the average of systems installed in North America. The common failures were categorized as mechanical due to wear and tear during operations, lack of maintenance and improper design. Some of the reasons for early failure were attributed to improper manufacturing and installation of new systems. Delegation to the suppliers of the design, selection and installation of PCP was a good approach during the learning curve of operators (Petrotrin Trinmar Personnel), however as the systems were fully adopted by the company, appropriate training and development of a culture associated to the use of PCP needed to be developed since these classic systems can turn into new technologies due to their scarce use.
PCP Management should be taken as an integrated vision in accordance with the development of the Soldado field due to the need to maximize production and the high economic impact that the products and services associated to PCP have on lifting costs.
Drilling Optimization Platform for Well Cost Optimization
Authors: Sawh Viveka , Solomon Herlene 
Published: June 2016

Abstract
As operators strive to become more efficient on cost and performance during well construction, their approach to tracking invisible lost time (ILT) and non-productive time (NPT) has been revamped. A state-of-the-art software platform has been introduced into the market to monitor and optimise drilling performance in real-time, enabling early detection of ILT and NPT events, ultimately saving rig time and reducing associated costs.
Given the current economic climate, this platform allows for a smart approach to reduce inefficiencies when drilling a well by its innovative approach of benchmarking and monitoring. One of the competitive advantages of utilising this platform for a drilling advisory service is the pre-job study, in conjunction with the operator, to develop the key performance indicators (KPI) that will be referenced as benchmarks for real-time trend monitoring.
Up to 39 different KPI's, such as rate of penetration, on and off-bottom time, circulating and connection times are determined, however for this study, the performance indicator of connection times while drilling and tripping will be analyzed. With a more user-friendly interface, optimized for 24/7 trend monitoring, this platform serves to be a more beneficial and market-leading approach to performance monitoring.
The aforementioned, coupled with breakthrough thinking, reveals the potential for savings which can be harvested by the operator by driving operational performance, resulting in more proficient operations. This paper will showcase one such case history to reveal missed opportunities and the associated cost and value benefits.
New Challenges in Construction and Production Prediction Using Multilateral Well to Develop Ecuadorian Oilfield in Environmental Sensitive Areas
Authors: Bone Romel Erazo , Aguilar Fidel Chuchuca , Segovia Kenny Escobar 
Published: June 2016

Abstract
Design the multilateral well trajectory in vertical section, like to dual lateral and fishbone wellbore, for drainage M-1 and M-2 reservoir and perform a numerical reservoir simulation to predict the behavior of production for each of the types of multilateral wells.
The use of different configuration of Multilateral well technology would help to increase the drainage reservoir area and the oil production form singular well path, also reduce the amount of drilling well for the development oil field, leads directly to the reduction of spatial area required for well-path, which is very beneficial for the environment because it let to decrease the impacts and footprint on the oilfield area, also the use of ML technology helps reduce costs directly related with drilling wells.
This study had been divided in two stage to have a better performance. Therefore the first stage is designing a multilateral well trajectory and the second stage is determine the performance of productivity using multilateral well (dual lateral-fishbone)
Nowadays the environmental sensitive areas it's a very concern factor to considerer into the design and development oil and gas project, especially when there are a lot of oil reserve proved into this area, therefore during the design phase of the oil project is very important considering the footprint into the oilfield.
Also in this work we studied the technical and economical applicability of multilaterall wells in reservoirs with the properties and characteristics of Ecuadorian reservoirs in environmentally sensitive areas, where the theoretical reservoirs were simulated at different scenarios varying values of vertical permeability, length of open zone. Also we built an economical model, using Microsoft Office Excel 2007, for the economical analysis, tacking care account of the cost of all the taxes fixed by the State.
Efficient Development Method for High-Viscosity, Complex Fault-Block Reservoir
Authors: Xu Shiqian , Feng Qihong , Guo Fajun , Yan Aihua , Liu Shumin , Tao Yayuan , Chen Xiaoqin 
Published: June 2016

Abstract
XXX unit of Huabei oilfield, a complex fault-block and high viscosity reservoir, has stepped into middle period of development. Though the water cut has reached 81%, only 4.7% of the original oil in place (OOIP) has been produced, indicating that the current development method for this block may be inappropriate.
In order to improve the production performance of this block, we studied the proper development technique on the basis of its geologic features. We examined the applicability of combining individual layers, and determined the upper limit for the segments of an injector as well as the optimal injection rate for each segment. In addition, we estimated the reasonable well density, the oil production rate, the injection-production ratio, and formation pressure using both numerical simulation and reservoir engineering method.
We further coupled reservoir simulation with an optimization algorithm to provide proper measures for the improvement of oil recovery. The first measure examined is to divide layering segments and complete the well pattern. Our simulations give the optimized position of new wells. The primary oil recovery of two layering segments increases by 2.33% and 1.75%, respectively. The second one is the optimization of liquid production rate. In comparison with the current development state, the optimized schedule will increase the primary oil recovery of the two segments by 2.1% and 1.2%. Therefore, the optimized technique may serve as an effective approach to develop other fault-block reservoirs.
In this work, several development methods demonstrate a significant effect to enhance oil recovery for complex fault-block reservoir, which can give a good guidance for other similar reservoirs.