bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Blasingame Type Curves to a Multi-Well Gas-Condensate Reservoir: Field Case Study
Authors: Adrian Pedro Marcelo , Cabrera Marcia Ruth 
Published: June 2018

Abstract
Nowadays advanced decline curve analysis techniques are widely accepted for estimating Hydrocarbon Initially in place (HCIIP), reservoir parameters and production forecasting. These analytical techniques were developed assuming different reservoir models and wellbore geometries. Most of them considered an ideal single well reservoir system, which is not a common scenario of production.
In light of that, some authors have proposed theoretical solutions for the analysis of production data of multi-well reservoir. Gas and oil reservoirs has been studied and validated with reservoir simulation models; however the application to real field case was not addresses in detail. There is an example for gas-condensate reservoir with the multi-well approach and the other for an oil field by applying a single well methodology.
This paper presents a field case study application of Blasingame type curve method to a multi-well gas-condensate reservoir. Total material balance pseudo-time was calculated using the two-phase compressibility factor. Bottomhole flowing pressures were calculated with vertical flow correlations and adjusted with dynamic gradients. A single well production data was analyzed to estimate the total Original Gas In-Place of a gas-condensate reservoir as well as reservoir parameters.
The results of the multi-well method were comparable with volumetric and conventional material balance estimations, as well as well testing interpretation results. Therefore the reliability of the multi-well type curve approach to gas-condensate reservoirs was confirmed.
Engineered Wellbore Strengthening Application Enables Successful Drilling of Challenging Wells
Authors: Chimara Godwin , Calder Alan , Amer Wael , Leslie Philip 
Published: June 2018

Abstract
Four wells were successfully drilled and completed, but high drilling fluid densities (1.95 to 1.98 SG) were necessary to maintain wellbore stability in the overburden section immediately above the depleted reservoir. The estimated hydrostatic overbalance from the drilling fluid was approximately 800 bar (11,603 psi) higher than reservoir pressure. A wellbore strengthening technique was selected to seal the calculated 1500 μm fractures induced by these high pressures. This paper highlights the engineering, logistical, and operational challenges encountered while successfully drilling and completing such wells.
Geomechanical data was initially acquired, including Young's modulus, Poisson's ratio, and minimum in-situ horizontal stress; and, together with the operational parameters [hole diameter and equivalent circulating density (ECD)], these data were used to estimate fracture width (1500 μm). Subsequently, a drilling fluid system was engineered and customized to seal such fractures, thereby strengthening the wellbore to help minimize losses in the reservoir. The solution was validated at two separate laboratories. Large particulate materials with a D50 of 600 to 2300 μm were used. Improvement opportunities during execution were captured for the next cycle.
A total drilling fluid loss of 512 m3 during a 16-hour period was experienced in one well after a drilling liner packoff occurred, and fractures greater than 1500 μm were initiated; however, the liner was successfully cemented in place. The coarse particulate materials (600 to 2300 μm) were mobilized in 500 and 1000 kg bags to minimize deck space requirements on the rig and help facilitate ease of mixing. Rig mixing and pit agitation capacity were important for effective mixing of the fluid system. The application also provided the opportunity to align testing procedures and equipment between the field and laboratory. With increasing reservoir depletion, the potential exists for fracture width increases that can impact the particle size of materials necessary to effectively design a solution. Engineered particulate solutions provided a pathway for sourcing and procuring the necessary wellbore strengthening materials.
Determining the Feasibility of Immiscible CO2 EOR Projects in Trinidad's Mature Fields
Authors: Ramnath Jonathan , Felix Elroi , Shah Ahmid , Soroush Mohammad , Omokughegbe Nykesi , Jaipaulsingh Francis 
Published: June 2018

Abstract
Decreasing oil production and increasing quantities of greenhouse gases continue to be an issue plaguing Trinidad and Tobago's energy sector. While CO2 EOR has been proven to be an effective solution to both of these problems it is often overlooked in Trinidad due to the inability of the gas to achieve miscibility with the crude oil as well as operational limitations such as an absence of transportation pipelines for the CO2.
Even though miscibility may not be achieved, immiscible CO2 EOR can effectively increase production and sequester CO2 resulting in an increase of revenue as well as decreasing the quantity of greenhouse gases vented to the atmosphere. This paper aims to highlight the possibility of implementing immiscible CO2 projects in Trinidad. The scientific processes that are responsible for increased crude oil production are discussed and the operational considerations for a safe and economically feasible project in Trinidad South West fields are examined.
It was seen that the vaporizing gas drive process would not result in miscibility in the shallow low pressure fields of the South West Trinidad however it would cause a significant reduction in the interfacial tension, this in turn causes an increase in the capillary number which would result in additional oil recovery. It was also found that the high viscosity of the non-carbonated oil of the region would result in an even greater reduction in viscosity when it is mixed with the CO2 gas resulting in more favourable oil mobility. The high solubility of CO2 in hydrocarbon liquids result in the swelling of crude oil. In the water wet formations, the oil within the pore spaces swells, resulting in an increase of relative permeability aiding in additional oil recovery.
In the field evaluated, it is proposed that the CO2 be acquired from Atlantic LNG, tube trailers be used to transport the CO2, 100mmscf of gas injected per day with a 5spot injection pattern and the produced gas compressed and reinjected. From simulation this was found to produce an additional 389,360bbls of oil where CO2 would be sequestered and an additional profit of US$ 21,414,800 would be acquired within a 20 year period.
An Experimental Investigation of Proppant Diagenesis and Proppant-Formation-Fluid Interactions in Hydraulic Fracturing of Eagle Ford Shale
Authors: Elsarawy Ahmed M. , Nasr-El-Din Hisham A. 
Published: June 2018

Abstract
Proppant diagenesis has been introduced recently as a damaging mechanism to the fracture conductivity in shale formations. The mechanism was used to explain the low values of the field-measured fracture conductivity as well as the long-term decline of the lab-measured API conductivity data. Previous studies revealed the presence of a diagenetic overgrowth on the proppant surface and around the embedment crater after being exposed to high-temperature and/or high-stress conditions. The objective of this paper is to experimentally investigate the diagenesis of bauxite proppant in calcite rich Eagle Ford shale fractures.
The interaction between the proppant and the formation was studied by aging its mixture in a deionized water for prolonged period of time at elevated temperature of 325°F to accelerate the involved reactions. Aluminum-based bauxite proppant of 20/40 mesh-size was mixed with a crushed Eagle Ford shale sample of 50/100 mesh-size. The mixture was aged at 325°F and 300 psia for three weeks. The surfaces of the proppant and the formation were examined for mineral overgrowth and dissolution using scanning electron microscope (SEM) with energy dispersive X-ray spectroscopy (EDS). The supernatant fluid was analyzed for cations’ concentrations using inductively coupled plasma (ICP) and the sulfate ion concentration was measured using a spectrophotometer. The proppant and Eagle Ford formation were then aged separately at the same conditions to explain the sources of the leached ions and the observed overgrowth materials.
The results show the diagenetic activity that could result from the use of bauxite proppant in Eagle Ford shale fracturing. The ICP results indicated the potential dissolution of the proppant at high temperature. The observed overgrowth materials were identified as calcium sulfate, calcium zeolite, and iron-calcium zeolite. The calcium sulfate was found to be explicitly sourced from the Eagle Ford dissolution-precipitation mechanism. The SEM/EDS results indicated the presence of calcium zeolite after aging both cells: the proppant/formation mixture and the formation alone. The iron-calcium zeolite was found on the proppant surface as a result of the fluid/proppant/shale interactions.
The study contributes to the understanding of the damaging mechanisms to the fracture conductivity in the Eagle Ford shale formation. Results impact the choice of proppant and fluid for fracturing optimization and long-term production sustainability in the Eagle Ford shale reservoirs.
History Matching of Naturally Fractured Reservoirs Using Pressure Transient Analysis and a Case Study
Authors: Vaughan Rhodri , Hicks Joseph , Chasqui Efrain , Velarde Javier 
Published: June 2018

Abstract
This paper presents a modelling workflow to efficiently history match naturally fractured reservoirs using Pressure Transient Analysis (PTA) with application to a complex naturally fractured sandstone reservoir.
Incorporated in the modelling workflow is the use of deconvolution to streamline the history matching process. To ensure this workflow is flexible to mature fields with interference between wells, a work around to achieve a similar output to multi-well deconvolution is presented.
The modeling workflow was successfully applied to a case study resulting in reduction of computer processing time by around 60%. The product of this workflow was not just a single dual-porosity model which best matched the historical data-set, but a suite of models which sample the range of possibilities. From the multiple history matched models, the low (P90), mid (P50) and high case (P10) models were selected statistically.
Fracture porosity is shown to be the input parameter with largest impact on the pertinent simulation outputs in the case study such as time to water breakthrough, pressure match and recoverables. As such, time should be spent gathering and processing data to narrow the uncertainty range. However, care should be taken not to reduce the range prematurely as fracture porosity estimation is a source of wide uncertainty.
Additionally, the case study highlights that horizontal anisotropy can have a significant impact on the field GIIP during the history matching process and consequently impact the reserves in a fractured field. In the case study, the introduction of horizontal anisotropy not only improved the history match but also increased the field GIIP post-history match by around 30%. The value in studying anisotropy within a fractured field and its inclusion into modeling is clearly demonstrated.
This paper brings together various innovative data interpretation approaches and modeling techniques and presents them in an applied workflow. The workflow shows the practicing engineer how they can best interpret and utilize the available data-sets through the application of PTA. The result is not only a better history match, but also a more efficient process which provides a statistical representation of the likely possibilities of the naturally fractured system.
Shorebase Logistics for Deepwater Drilling Operations in Trinidad, Guyana and Suriname
Authors: Razack Javed , Nazir-Khaleel Imtiaz , Rampersad Shaun , Zambrano Alvaro , Chandarjeet Shivani , Choon Sachin 
Published: June 2018

Abstract
Since 2015, over a dozen deepwater exploration and appraisal wells have been drilled across Trinidad, Guyana and Suriname. By 2020, these three countries are expected to see at least another twenty-five deepwater wells being drilled. These include 17 development wells for Guyana's massive Liza field. Seismic exploration is also being conducted over unexplored deepwater blocks in Guyana and Suriname, which could pave the way for even more wells during this period.
A key element in the offshore drilling supply chain is the onshore supply base. This shorebase is the logistics hub for all drilling activity. Supply vessels commute between the rig and shorebase, where they are loaded with all drilling fluid, cement, drillpipe, logging tools, food supplies, and any other equipment needed by the rig. Fuel and potable water for the rig are also loaded at the shorebase. When the vessels return from the rig, they unload waste generated at the rig and demobilize tools, unused drillpipe and so on.
The shorebase must have the following: covered warehousing, flattened and reinforced laydown yard, offices for support staff, and quayside access with a dock that is long enough and with deep enough draft to accommodate the supply vessels when fully laden with cargo. The shorebase must also have sufficient crews for loading and unloading of materials, as well as heavy equipment such as cranes and forklifts. Vessels must also be able to access electric power and load potable water, drill water and fuel.
In Guyana and Suriname, natural deepwater ports do not exist due to sedimentation from several rivers like the Berbice, Essequibo, Demerara and Paramaribo. The severe draft restriction means that the large supply vessels required to take cargo to the rig cannot easily dock in Guyana or Suriname. Moreover, Trinidad has many major multinational service companies already set up, so the majority of equipment and materials needed for drilling must emanate from Trinidad. Further, since Trinidad has a mature oil and gas industry, there are several shorebases already set up to service drilling operations. As a consequence of these three main factors, the primary shorebase for all wells in Guyana and Suriname have been located in Trinidad.
With the Liza field being developed, ports are being renovated in Guyana while more service companies are aiming to set up there. However, until a deepwater shorebase is built in either Guyana or Suriname, the primary supply base for these wells must come from Trinidad. Secondary supply bases have been located in Guyana or Suriname, to facilitate smaller supply vessels and emergency support.
The Role of Adsorbed Water on Pore Structure Characteristics and Methane Adsorption of Shale Clay
Authors: Feng Dong , Li Xingfang , Zhao Chaojie , Li Jing , Liu Qing , He Minxia , Zhao Wen , Qin Jiazheng 
Published: June 2018

Abstract
Water is ubiquitous within the shale reservoirs and mainly stored in the hydrophilic clay minerals. The water distribution characteristics are important for the gas-in-place and gas production. In our work, water vapor adsorption on montmorillonite (Mt), kaolinite (Kaol) and illite (Il) were performed to investigate the water adsorption behaviors. Then, the samples were conducted with N2 gas-adsorption techniques to investigate the effect of adsorbed water on pore structure characteristics. The results show that (1) the PSD curves under different RH condition has validated the condensation effect and also demonstrated the heterogeneity of water distribution which varies with the pore scale. Under a certain moisture condition (RH=98%), the small pores (approximately less than 5nm) are blocked with the capillary water while large pores are covered with the adsorbed water film. (2) The pre-adsorbed water occupied more pore volume with the increasing of RH, the corresponding quantitative water saturation based on the nanopore size distribution of moisture-equilibration samples can reach to 51.99%, 71.43% and 46.15% at RH of 98% for Mt, Kaol and Il, respectively. The numerical range is enough to represent the value of actual reservoir. (3) The contribution of clay minerals to the methane adsorption capacity is over overestimated in dry condtion. Under certain water saturation, the smaller pore is filled with capillary water while larger pores are covered with water film, the adsorption forces is changing from solid-gas interaction to liquid-gas interaction. This phenomenon also give the reasonable explanation to the critical water content, Up to a this point, the further increasing of water content would not affected the methane adsorption ability. Therefore, the adsorption for clay minerals can be negligible comparing with the hydrophobic organic pores.
Property Changes of Formation Rocks under Electromagnetic Heating: An Experimental Study
Authors: Hu Lanxiao , Li Huazhou , Babadagli Tayfun 
Published: June 2018

Abstract
Electromagnetic (EM) heating has been proposed to recover heavy oil due to its great environmental friendliness. Previous studies focused on investigating the feasibility and enhancing the oil recovery of such non-aqueous method. However, the effect of EM heating on the variations of formation rock properties is still elusive. Detailed experiments/measurements are required to understand the effect of EM heating on changing the petrophysical properties of formation rocks.
A commercial microwave oven is used to conduct the EM heating experiments. Different types of formation rocks (shale, Berea-sandstone, tight sandstone, and Indiana-carbonate) are investigated. Various techniques, including scanning electron microscopy (SEM), energy dispersive X-ray (EDX), N2 adsorption/desorption, and X-Ray fluorescence (XRF), are used to characterize the properties of shale samples before/after experiments. The porosity and permeability measurement are performed to Berea sandstone, tight sandstone, and Indiana carbonate. An infrared thermometer is used to measure the samples’ surface temperatures. Furthermore, oven-heating experiments are conducted to distinguish the effects of conductive-heating and EM heating on the property changes of rock-samples.
Results show that different types of rocks exhibit different responses to EM heating; shale samples exhibit a higher temperature compared with sandstone and carbonate because of the better EM energy absorbance of clays and pyrite. The shale samples are crumbled into pieces or fractured after EM heating, while the sandstone and carbonate samples remain almost unchanged after EM heating. The SEM results reveal that EM heating causes tensile failure, shrinkage of clay, and release of volatile organic content to the shale sample. The N2 adsorption/desorption measurements demonstrate that the pore volume significantly increases due to clay shrinkage, while part of the pore can be blocked by the converted bituminous kerogen after EM heating. EM heating has almost no effect on Berea sandstone and Indiana carbonate due to the transparency of quartz and calcite to EM waves. However, the EM heating can fracture the tight sandstone that is saturated with water because of the rapid rise of pore pressure under EM heating.
Liza Field Development - The Guyanese Perspective
Authors: Alleyne Keron , Layne Lugard , Soroush Mohammad 
Published: June 2018

Abstract
In May 2015, ExxonMobil successfully brought in the Liza 1 wildcat well, 120 miles off the coast of the South American nation of Guyana in the Stabroek block, in the Guyana-Suriname basin. Prior to the Liza 1 success, there were 22 wells drilled by other companies, all of which proved to be non-commercial. ExxonMobil stated that recoverable reserves from the Liza field – Phase 1 development would be in the range of 0.8 – 1.4 billion barrels of oil equivalent.
The Liza field is part of one of the most prospective basins in South America based on a US Geological survey report - the Guyana-Suriname basin. A representative model was created using Petrel, Wellplot Digitizer, PROSPER, CMG and Microsoft Excel and consists of eight (8) producers, three (3) gas injectors and six (6) water injectors as outlined in the ExxonMobil Phase 1 development plan. Simulation results indicate that over a twenty-five (25) year period approximately 456 MMSTB of oil and 3.5 TCF of gas, equivalent to 1.04 billion BOE will be recovered from the Liza Phase 1 development.
Based on the Production Sharing Agreement between the Guyana government and ExxonMobil, an economic assessment was undertaken which quantifies the government share of revenues to be obtained from the Liza field – Phase 1 development. The variables in this economic evaluation included capital expenditure (CAPEX), oil and gas price, operational expenditure (OPEX), 2% royalty payment, cost recovery mechanism and 50% profit split to the Guyana government.
Based on ExxonMobil estimated capital investment of $US 4.5 billion, an oil price of $US 50/bbl, gas price of $US 2.50/MMBTU and this project's projected operational expenses over the twenty five year period, total new revenue to Guyana over this period will amount to $US8.9 billion. It is also estimated that Guyana's share of the development cost will be paid back within six (6) years of commencement of production of the Liza field.
3D Geomechanical Modeling for Wellbore Stability Analysis: Starfish, ECMA, Trinidad and Tobago
Authors: Ramjohn Rashad , Gan Thomas , Sarfare Manoj 
Published: June 2018

Abstract
Conventionally, a calibrated 1D geomechanical model is used to define the mud weight window required for the successful drilling and completion of a well. Utilizing depth stretch functionality, estimated rock properties and subsurface stresses, are ‘stretched’ from the corresponding offset well to the proposed well to be drilled. This approach will only suffice if the geological structure and wellbore trajectory are relatively simple. Even so, optimizing wellbore placement becomes an arduous exercise when using 1D geomechanical models because the workflow must be repeated for each new iteration of the proposed wellbore trajectory. Furthermore, as the geological structure and wellbore trajectory increases in complexity, severe distortion in topological properties, such as overburden stress and pore pressure, can render the one-dimensional solution inapplicable.
In such circumstances, a calibrated 3D geomechanical model can be used. This paper introduces a generic workflow for developing a calibrated 3D geomechanical model that can be used for wellbore stability analysis. The workflow incorporates calibrated 1D geomechanical models and existing static geological modeling outputs, such as structural surfaces and facies model, to constrain the distribution of topological and primary properties within a 3D structural framework. The applicability of the workflow will be demonstrated by presenting the results of a case study from the Starfish field, ECMA, offshore Trinidad. It is intended for this paper to serve as a reference to geoscientists and engineers involved in brownfield and greenfield development planning. By extension, subsurface professionals who are involved in integrated reservoir modeling may also benefit from the work presented since geomechanics is often omitted from the modelling workflow.