bluuebunny/crossref_metadata_2025_split huggingface dataset:
Chemical Deliquification of Unconventional Gas Wells
Authors: Francis-LaCroix K. , Seetaram D. 
Published: February 2021

Abstract
Trinidad and Tobago offshore platforms have been producing oil and natural gas for over a century. Current production of over 1500 Bcf of natural gas per year (Administration, 2013) is due to extensive reserves in oil and gas. More than eighteen of these wells are high-producing wells, producing in excess of 150 MMcf per day. Due to their large production rates, these wells utilize unconventionally large tubulars 5- and 7-in.
Furthermore, as is inherent with producing gas, there are many challenges with the production. One major challenge occurs when wells become liquid loaded. As gas wells age, they produce more liquids, namely brine and condensate. Depending on flow conditions, the produced liquids can accumulate and induce a hydrostatic head pressure that is too high to be overcome by the flowing gas rates. Applying surfactants that generate foam can facilitate the unloading of these wells and restore gas production.
Although the foaming process is very cost effective, its application to high-producing gas wells in Trinidad has always been problematic for the following reasons: Some of these producers are horizontal wells, or wells with large deviation angles.They were completed without pre-installed capillary strings.They are completed with large tubing diameters (5.75 in., 7 in.).
Recognizing that the above three factors posed challenges to successful foam applications, major emphasis and research was directed toward this endeavor to realize the buried revenue, i.e., the recovery of the well's potential to produce natural gas. This research can also lead to the application of learnings from the first success to develop treatment for additional wells, which translates to a revenue boost to the client and the Trinidad economy. Successful treatments can also be used as correlations to establish an industry best practice for the treatment of similarly completed wells.
This paper will highlight the successes realized from the treatment of three wells. It will also highlight the anomalies encountered during the treatment process, as well as the lessons learned from this treatment.
Efficient Proppant Flowback Prevention Strategy Allows Production of a Multi Fractured Offshore Horizontal Well Equipped with ESP and Screenless Completion
Authors: Martocchia F. , Baretti S. , Farina L. , Rizza G. , Okassa F. , Dirya A. D. , Haaland T. G. 
Published: February 2021

Abstract
When production facilities are not equipped with a solid control device, proppant flowback becomes an issue throughout the entire productive life of a screenless multi fractured well. The challenge of minimizing proppant flowback is even more critical when dealing with offshore horizontal wells with ESP systems installed.
A wide selection of proppant flowback prevention additives is now available in the industry: most of them work either chemically or mechanically. At low formation temperature (150 F), the effectiveness of some additives such as resin coated proppant or fiber can be limited due to the temperature activation.
This paper will describe a successful strategy of proppant flowback control which was implemented in a multi stage fracturing treatment on a horizontal well in M- field, offshore Congo. It is the combination of resin coated proppant, enhanced by a chemical activator and inert fibers that provides double mechanism to eliminate proppant flowback issues during well production and sustaining life of ESP.
Success in this multi stage fracturing treatment has resulted in oil production from a pay zone that has never been produced due to poor petrophysical characteristics.
This document will describe: proppant flowback control additives selection process, placement strategy, hydraulic fracturing design and well execution considerations for multi stage fracturing treatments.
The Impact of Laminated Rock on Hydraulic Fracture Propagation in Unconventional Resources
Authors: Cherian B.V. V , Higgins-Borchardt S. , Bordakov G.A. , Yunuskhojayev A. , Al-Jalal Z. , Mata D. , Jeffers J. 
Published: February 2021

Abstract
As unconventional reservoirs continue to be discovered and appraised, an ever increasing challenge is to understand the productive mechanism that unlocks the potential of these reservoirs. Since most unconventional reservoirs have some degree of lamination (varying from a few hundreds of an inch to a couple of feet), a technical hurdle exists in understanding the integration of conventional logging (using up-scaled measurements), modeling software (assumptions, gridding, numerical/P3D) and fine scale measurements (core measurements).
Laminated reservoirs pose many challenges in the decision making process especially when a model centric, data driven approach is utilized. These challenges can be reduced to two categories: (1) challenges in understanding fracture propagation mechanism and (2) challenges in reservoir characterization. This paper focuses on a procedure to capture the former. The early phase of gathering measurements is frequently executed with data sets and measurements that are incomplete and insufficient to understand the production mechanism in these low porosity environments. In an engineering analysis, this data may be utilized only to a limited extent, due to the inconsistences in the measurements gathered at various scales. To overcome these inconsistencies a novel approach to estimate mechanical properties with sub-sonic resolution through integration of sonic logs, high resolution logs, and facies classification has been developed.
The use of traditional workflows to derive mechanical properties has led to overestimating and/or underestimating rock strength and stress in the different layers. This, historically, has resulted in inconsistent conclusions across various disciplines and unexplainable well performance. Furthermore, the process of matching hydraulic fracture net-pressure using conventional workflows can result in the complication of fracture propagation process or incorrect calibration of the Mechanical Earth Model used to estimate earth stresses. We have demonstrated that the presented workflow allows for more accurate estimation of the mechanical properties profile in thin bed formations and consequently more effective use of those estimates to design hydraulic fractures and analyze the results.
The Performance Characteristics of Waterdrive Gas Reservoirs off the South-East Coast of Trinidad
Authors: Welsh C 
Published: February 2021

Abstract
Sustained production is needed to satisfy the contractual demands of both Trinidad's domestic and LNG markets. To unlock the value of existing fields on production, comprehending the case histories of produced water drive reservoirs is necessary.
This study analyses production, reservoir and well data to understand trends in 12 water drive gas reservoirs from production to abandonment. These reservoirs were produced by 16 wells, from 5 fields located off the South East coast of Trinidad.
From the analysis, relative permeability Corey exponents were matched to fractional flow curves in a numerical simulator. The Buckley-Leverett-Wedge (B-L-W) technique was applied to predict the flooding order of the reservoirs, but was not found to be reliable because of its inability to compensate for layering and thick reservoir intervals. Nevertheless, the shape of the relative permeability curves could be used in some cases to identify a general grain size distribution. The endpoint values of the water curves in particular were correlated with the water-wettabilities of the reservoirs.
It was discovered that Recovery Factor (RF) before Water Breakthrough (WBT) was better with the high production rate reservoirs. Meanwhile improvement in RF after WBT depended on having a higher initial gas column. The pre-WBT result may have been caused by successfully outrunning the aquifer. The effect of increasing aquifer size was to lower RFs.
Single well completion reservoirs' WGR profiles depended on completion orientation. Vertical completions experienced WBT between 80 and 85 percent RF compared to horizontal and deviated wells at greater than 95 percent RF.
At conditions close to abandonment by water-out, phenomena such as liquid loading and condensate blocking were prevalent in a few reservoirs based on production trending.
A study limitation that may have led to incorrect conclusions was the inability to keep all other variables constant whilst manipulating only one. This could be remedied by a study with a larger number of reservoirs.
The Performance Evaluation of Old Well after SRV in Ordos Basin Tight Oil Reservoir
Authors: Wang H. , Liao X. , Ye H. , Zhao X. , Liao C. , Chen X. , Li D. , Li Y. 
Published: February 2021

Abstract
The technology of Stimulated reservoir volume (SRV) has been the key technology for unconventional reservoir development, it can create fracture network in formation and increase the contact area between fracture surface and matrix, thus realizing the three-dimensional stimulation and enhancing single well productivity and ultimate recovery. In China, the Ordos Basin contains large areas of tight oil reservoir with the porosity of 2~12 % and permeability of 0.01~1 mD. The most used development mode is conventional fracturing and water flooding, which is different from the natural depletion mode in oversea, but the development effect is still unfavorable. The idea of SRV is proposed in nearly two years in Changqing Oilfield. SRV measures are implemented in some old wells in tight oil formation. It is a significant problem that should be solved urgently about how to evaluate the volume fracturing effect.
Based on the real cases of old wells with SRV measures, the microseismic monitoring is used to analyze the scale of formation stimulation and the complexity of fracture network after volume fracturing; the numerical well test and production data analysis (PDA) are selected to explain the well test data, to analyze the dynamic data, and to compare the changes of formation parameters, fluid parameters and plane streamlines before and after volume fracturing; then the interpretation results of well test with the dynamic of oil and water wells are combined to evaluate the stimulation results of old wells after SRV.
This paper has presented a set of screening criteria and an evaluation method of fracturing effect for old well with SRV in tight oil reservoir. It will be helpful to the selection of candidate well and volume fracturing operation in Ordos Basin tight oil reservoir.
It should be noted that the evaluation method mentioned in the paper can be expanded to volume stimulation effect evaluation in other unconventional reservoirs, such as tight gas, shale gas and so on.
Applications of Advance Downhole Fluid Analysis and Interval Pressure Transient Test for Improving Oil Reservoir Characterization: A Case Study from the East Cost of Trinidad
Authors: Paul S. , Tapia R. , Arias-Correa J.A. 
Published: February 2021

Abstract
Acquisition of reservoir information from exploration campaigns in offshore oil reservoirs is a continuous challenge in today's operations. Reservoir fluid properties and reservoir parameters characterization are fundamental for the accurate reservoir description for field planning and facilities design. With the aid of new technology, data of the highest quality can be obtained while the well is being drilled. This data is a key input to the development plans for the area.
For an exploration well in an offshore Trinidad and Tobago oil field, in a reservoir of mainly unconsolidated sandstones with medium oil, the main objective was to acquire early and quick identification of the oil prospect for planning appraisal wells. A wireline formation tester (WFT) dual-packer module was deployed to perform an interval pressure transient test (IPTT), also known as a mini-drillstem test (mini-DST), at the interval of interest for assessing key reservoir parameters such as vertical and horizontal permeability, damage skin, and reservoir pressure, among others, in the near-wellbore domain, in addition to fluid sampling.
Downhole fluid analysis (DFA) was performed to identify the reservoir fluid properties including oil and water fraction, fluid composition, gas/oil ratio, density, viscosity, fluorescence, reflectance, and resistivity at multiple depths in real time. Also, the real-time insitu fluid characterization allowed making decisions about where and when to take the samples in an optimal amount of time. Additionally, a single-probe wireline formation tester was used to take fluid samples and to obtain a single-point formation pressure, used for determining pressure gradient. DFA was combined with pressure profiles to improve the determination of zonal connectivity across the reservoir.
The combination of IPTT and real time DFA characterization was applied at multiple depths and resulted in an improved understanding of oil reservoir, as well as lessons learned about methodology and applications and recommendations for future operations.
Reservoir Evaluation Using Interval Pressure Transient Test in Appraisal Gas Wells, Offshore Trinidad and Tobago
Authors: Bardal D. , Trim M. S. , Tapia R. , Arias-Correa J.A. , Baptista-Parra S.M. 
Published: February 2021

Abstract
Hydrocarbon exploration is a challenging, costly and high-risk investment and success often requires further drilling of one or more appraisal wells to acquire data of the highest quality for reservoir evaluation and characterization before development plans can be put in place. During the exploration and appraisal stages it is important to define the reservoir fluid properties and reservoir parameters to enable accurate economic assessments.
Three appraisal wells in two gas fields offshore Trinidad and Tobago were drilled in reservoir formations that are mainly unconsolidated sandstones with dry, biogenic gas. An extensive wireline logging program was planned which ranged from basic and advanced petrophysical logs to images and formation testers including the dual-packer module to perform interval pressure transient tests (IPTT) or ‘Mini-DSTs’ as these are also known.
This was the first time in Trinidad and Tobago that IPTTs were conducted on appraisal gas wells. Technical factors influencing the decision to use an IPTT as opposed to a full Drill Stem Test (DST) included access to data from existing full DST's acquired in a nearby offset wells and a specific need to target thin-bedded and laminated sands so as to evaluate them individually and to observe vertical interference or connectivity between sand units.
A combination of IPTT analysis and real-time downhole fluid characterization was applied to the appraisal wells which resulted in an improved understanding of the reservoir.
The IPTT planning, methodology and applications, along with insights on some of the challenges encountered during operations which included changes to drilling operations in order to achieve the planned formation evaluation are presented.
Downstream Refining and Petrochemicals Challenges - Future Configuration
Authors: Mohite S.D. 
Published: February 2021

Abstract
Precise predictions and solutions for tomorrow's needs are the key to building a growing, sustainable business. This requires a mixture of vision, strategic risk taking business model and investment in new technology.
Refining trends forecast is useful for predicting possible landscape, where in challenge would be to meet twice the energy levels from today with half the CO2 emissions by 2030. Increasing and diversification of world's energy supplies to support the population of over 8 billion then would be a mammoth task, given that the triangle of energy, food and water will be crucial.
Three fundamental factors that will influence and shape this setting are: Global products demand will rise by 1.1% - 1.3% annually by 2030 to over 115 million barrels per day, with marginal influence of crude oil prices;Reinforced legislation targeting reduction of GHG emissions, requiring improved clean transportation and bunker fuels - accounting 2/3rd of total demand and growth;Refining and Petrochemicals form the backbone of global economics and meeting demand with inevitable steady profitability is a major task possibly also using alternative unconventional sources.
In competitive context – innovation, operational excellence and implementation of robust strategies are critical for sustenance and growth. Project returns can however be enhanced by incorporating integration principles and model at the design stage itself. Whilst development pace of new technologies would accelerate which can radically alter business structure in certain geographies, question remains on what makes a successful project come to fruition.
The presentation discusses futuristic economic unlocking of value by application of technology models and best practices by utilizing various feed-stocks, including natural gas as a main competitor and maximum upgrading bottom-of-the-barrel. Besides, novel process designs and operational control would be squeezed as it is invariably the last fraction which is most difficult to remove!
This paper contains forward-looking scenario about global Refining strategy, Petrochemicals feed-stock cost advantages, technology diversification routes to maximize returns from cheaper sources, financial performance and economics, growth opportunities in various countries, sectors or markets, besides a focus on Europe and GCC regions and current projects in Kuwait. However, these involve uncertainty as they depend mainly on future circumstances like commercializing R&D, not all of which can be controlled or accurately predicted, hence are directional for investment decisions.
LNG Imports - A Strategic Choice for GCC Region
Authors: Mohite S.D. 
Published: February 2021

Abstract
Although Middle East region is blessed with 43% of global proven gas reserves equivalent at 80 trillion cubic meters, of which 50 % are in the Gulf Cooperation Council (GCC) countries, apart from the challenge of historic under-investment, regional gas endowments have been highly uneven and unique.
The region is responding to gas shortages by boosting supplies through a combination of E&P developments and imports. As per IEA, the current 240 billion cubic meters (BCM) demand is expected to rise to 300 BCM by 2020 and 600 BCM by 2030. About 90% of incremental energy demand for power generation would come from gas then.
Strategic investment will have to focus on creating large volumes of storage capacity as well as peak deliverability to cope with rising imports and power demand requirements.
Currently, Dubai and Kuwait import LNG through floating storage and regasification unit (FSRU) projects. At first these imports were seasonal (i.e. summer demand for electricity for air conditioning) and on a spot or short-term basis. Now, demand extends into all but the winter months and soon demand will be year round.
The expansion of FSRU in Kuwait in to a permanent facility would increase capacity from 500 MMSCF/d to 3 BCF/d in two phases. This 11.0 million ton per annum (MMTPA) Kuwaiti LNG project under phase-I, is likely to replace the country's FSRU by 2020, mainly to replace the fuel oil firing in power plants.
Abu Dhabi is developing a 8.7 MMTPA project in the Emirate of Fujairah on the Indian Ocean outside the Strait of Hormuz. Depending on supply-demand dynamics, Abu Dhabi may be both an importer and exporter of LNG, possibly relying on gas from the Shah and Bab fields. Bahrain has plans to develop 3.6 MMPTA shore-based import facility.
Oman has combined Oman LNG and Qalhat LNG projects for integrated benefits, is developing unconventional gas reserves and would reduce gas subsidies to improve the demand equilibrium. Yemen continues to export LNG but has interruptions because of security issues.
While Qatar gains geo-political benefits from its broader LNG export customers, with plans to expand its LNG capacity further, the possibility of it supplying gas to its neighbors is remote. Whereas, Saudi Arabia is better dedicated to its oil-field development, has realized benefits of developing and commercializing its gas fields, for both power and job generation.
In view of the above, LNG thus remains a strategic choice for GCC countries mainly due to: Most environment-friendly and efficient option for rapidly escalating power demand at ~ 8% p.a.Techno-economics favoring fuel mix of LSFO and LNG for power and industries, instead of crude and dieselRefinery-Petrochemical integration becomes a more viable optionLimitations on geo-technical and geo-political contentious issues on developing non-associated gas fieldsChallenges on speeding up trade and strengthening exchange of power using 2009-set GCC grid, at full capacitySlow diversification into high-profile renewable power projects and its bold initiatives
A New Wave of Illumination -ISS OBC Acquisition in the Columbus Basin
Authors: Rampersad T. , Cegna A. , Steiner C , Kommedal J. 
Published: February 2021

Abstract
The Independent Simultaneous Source (ISS) seismic acquisition in the southern Columbus Basin conducted by WesternGeco for BPTT is in the early stages of seismic processing. Early results are already revealing improved imaging and structural interpretations.
Improvements in imaging and depth conversion are compelling, largely the result of full azimuths, longer azimuths, higher fold, lower frequency content and P/Z recording. Because of these factors the resultant OBC data leads to improved velocity model building utilizing BP's Full Waveform Inversion, FWI, techniques.
In a field wide comparison done in the southern part of the basin the OBC image provided marked increases in the following over the heritage streamer data; Fault clarity, where reflector terminations and linkages are much clearer.Reflector continuity, especially in the deeper (greater than 12,000 ft. depths). This improvement seen throughout the dataset is most noticeable below shallow gas accumulations and in areas next to platforms previously only covered by lower fold data. Seismic sequences are also now more interpretable.Flat-spot detection where previous identification was unknown.Early results also point to improved spatial positioning of reflectors under shallow gas accumulations and, in the depth migrated volumes, the removal of the sag due to incorrect velocity fields.
This paper illustrates comparisons in the Columbus Basin between the new OBC data and heritage streamer data in support of the above claims of improved image and depth positioning.