bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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.
Uncertainty Analysis using Design of Experiments to Assess the Development Plan of a North Sea Field
Authors: Guerrero Angel , Stephen Karl
Published: June 2018

This study assessed the impact of static and dynamic variables in EUR and NPV in the development plan of a North Sea offshore field with 81 m of water, light oil crude of 40.5 API and 510 SCF/STB of GOR comprised of sandstones from a shallow marine environment in anticline structure separated to the northeast and southwest by a pair of normal faults. The analysis is conducted through the application of different experimental design techniques and the preparation of a comparison between them. Uncertainty analysis has been prepared to characterize the appropriate range for nine variables that affect the oil recovery and net present value of the field development. A Folded Plackett-Burman design was prepared to screen the initial nine variables; the linear regression results show that the oil water contact, permeability anisotropy and net to gross are the significant variables. Also, the residual analysis demonstrated that the proxy equation should be improved to have better predictability in the non-sampled space. In consequence, a D-Optimal and a Central Composite experimental design were prepared for the three significant variables. The regression results show better coefficient correlation and lower least square errors in the D-Optimal design using a full quadratic model and confirmed the oil water contact as the most significant variable of the field. Finally, Monte Carlo Simulation was performed in the proxy model from the D-Optimal design, which resulted in an expected value ultimate recovery of 357 MMSTB. The paper presents an exciting workflow to analyze different experimental design techniques, compare them and use the most suitable to prepare the development plan of a field.
Economical Mature Field Revitalization in Low Oil Prices Environment: A Ten Thousand Incremental Oil Production Case Story in the Drago Complex Field, Ecuador
Authors: Izurieta Alvaro , Cuenca Dario , Pozo Lenin , Padilla Wilson , Bustos Jairo
Published: June 2018

This paper presents the results of the most extensive hydraulic fracturing campaign on the same field in Ecuador, along with the methodology appliedto establish the real field production potential and an incremental oil production of 10,000 STB/d.

The study started with the review of pressure transient analysis (PTA), resulting in updated values of permeability, skin and reservoir pressure, then conventional and special well logs were revisited to get a consistent approach of reservoir pay intervals. The characterization of formation damage mechanism was performed to confirm and complement the results. Strategic execution of the hydraulic fracturing workovers was implemented for fast track execution and to maximize results.

The rigorous and fundamentals-based review showed that additional production potential, on most of the wells in the field, could be achieved by hydraulic fracturing due to the high skin values and the deep penetration nature of the damaged zone. The interventions schedule of producing and nonproducing wells resulted in short deferred production times. All planned jobs were designed with the goal of reaching the maximum production defined by hydraulic fracturing and complete nodal analysis. Most fracturing jobs resulted in folds of increase, FOI, from 2 to 13. The learning curve started from one stage tip screen out, TSO, and conventional long fractures, to two stage hydraulic fracturing, pulsed proppant and propped acid fracturing jobs. Economical evaluation showed that the whole stimulation campaign recovered the investment during the third month of execution.

The incremental production outcome from these jobs resulted in ten thousandstandardbarrels per day, 10,000 STB/d, the historical peak oil of the field and the most extensive hydraulic fracturing campaign in the country.
Fault Leakage Assessment Using the Capacitance Model
Authors: Mohamdally Muzaffar , Soroush Mohammad , Zeidouni Mehdi , Alexander David , Boodlal Donnie
Published: June 2018

Fault transmissibility and leakage have significant implications for field development during both primary and post-primary recovery. Whether the fault is sealing or not can directly determine the sweep efficiency and the fate of injected fluids. In addition, fault transmissivity affect the accuracy of in-place volume calculations from material balance techniques. In this paper dynamic data was used to determine transmissibility and leakage of the faults via Capacitance Model (CM).

The CM has been developed from linear productivity model and material balance equation. Its inputs are production/injection rates and bottomhole pressure data (if available). The CM has weight factor for each well pair which determines the degree of connectivity between that pair. These weight factors were used and correlated to the fault transmissibility in this paper. Also, the CM was modified to incorporate the leakage in the system. New term, called leakage factor, was added for each well in the equation.

The model was examined through applying to several synthetic field data generated by CMG software. In synthetic fields, different faults with different throw and transmissibility were built and across the fault transmissibility was evaluated by the model. For creating leaking fault, upward leakage and flow along the fault were examined. Estimated zero leakage factor means no leakage and one means maximum leakage for the wells. The leakage factors not only identified where the leakage was happening, but also determined the amount of leakage by multiplying leakage factor to the net accumulation.

In reservoirs with complex geology and several faults, commonly encountered in Trinidad, all geological and geophysical complexities might not be accurately known. Using alternative methods such as the CM can complement, validate or better determine fault properties such as leakage and transmissibility for proper application of EOR schemes.
Experiment Studies on Horizontal Well - N2 - Viscosity Depressant - Steam Stimulation for Shallow Thin Super-heavy Oil Reservoirs
Authors: Sun Renyuan , Sun Ying , Fan Kunkun , Yang Shikai , Qiao Mingquan , Wang Xuezhong , Yang Yuanliang
Published: June 2018

In order to develop the super-heavy oil reservoir with thin layer, low reservoir temperature and shallow depth in CF oilfield of China, a new technology of HDNS (Horizontal well, viscosity Depressant, Nitrogen and Steam) was proposed and a series of experiments were conducted and the factors effecting oil recovery factor were analyzed. The self-designed equipment, which includes the steam generation system, gas injection system, chemical injection system, the sand-parking sample system, the temperature-controlled system, the metering system of produced fluids and the data collecting system, was used for the experimental studies. Experiments shows that the displacement efficiency increases with the increase of the steam temperature and the injection rate of steam, but too high steam injection rate will decrease the displacement efficiency because of Steam channeling. Compared with steam huff and puff, the displacement efficiency of viscosity depressant assisted steam (DS) increases about 20% because of the thermal chemical effect. The viscosity depressant, N2 assisted steam huff and puff (DNS) can increase the displacement efficiency in about 18% by using the synergistic effects of viscosity depressant, N2 and steam. In the process of DNS stimulation, the viscosity depressant can reduce the viscosity of super heavy oil combined with the effect of steam, which is called as thermal chemical effect. The N2 can prevent the steam chanelling in the reservoir and decrease the heat loss in the process of steam stimulation. The DNS stimulation can effectively reduce the oil viscosity and the steam injection pressure, expand the steam sweep efficiency. By using this technology, Block X of CF oilfield has been successfully developed in these years.
Casing Centralization and Pipe Movement in Cementing Operations for Improved Displacement Efficiency
Authors: Guzman Jose , Mavares Francisco , Monasterios Eloy , Massirrubi Luis
Published: June 2018

Casing centralization and reciprocation during a cementing operation can help improve the efficiency of annular mud displacement and provide a basis for analyzing the percentage of mud displacement efficiency. This information is necessary when developing a mitigation plan for any cementing operation's risk assessment when centralization and pipe movement are considered as operational variables.

A state-of-the-art, three-dimensional (3D) finite displacement efficiency simulator analyzes the percentage of mud displacement efficiency when these four main possible scenarios are considered: low, medium, and high centralization and casing reciprocation during the cementing operation. This paper discusses three case studies validated by a risk assessment process developed during the cementing job design stage in which higher standoff and casing reciprocation suggest improved mud displacement efficiency and low fluid channeling when the cementing operation is finished. Cement bond log (CBL) results are discussed and shared when high standoff and casing reciprocation scenarios are considered.

Results of this study include the following observations and conclusions: Casing reciprocation helps improve displacement efficiency, which can provide improved cement bonding.If casing reciprocation movement is not possible, high casing centralization standoff can be an effective design technique because it can be used to enhance mud displacement efficiency in cementing operations. Wellbore stability is not compromised by equivalent circulating density (ECD) increments resulting from the reduction of annular clear space when using centralizers.Design risk assessment should include a comparative scenario analysis to mitigate the potential risk of poor mud displacement efficiency when considering casing centralization with medium to high standoff and casing reciprocation.At some point, casing reciprocation will not be a factor of improvement for mud displacement efficiency when sufficient standoff is considered for cementing operation designs. This scenario can help mitigate any likelihood of poor mud displacement efficiency if the casing is not reciprocated because of operational factors.Even though high casing standoff yields high percent displacement efficiency, it is recommended to follow the primary cementing operation's field practices as discussed.

A comprehensive practical analysis to prepare a cementing risk assessment included in an operation's program is reviewed. It considers low and high casing centralization as well as pipe movement as variables to help improve cement placement.
Low Salinity Water Injection in a Clastic Reservoir in Northeast Brazil: An Experimental Case Study
Authors: Almeida Alana , Patel Rajan , Arambula Carolina , Trivedi Japan , Soares João , Costa Gloria , Embiruçu Marcelo
Published: June 2018

Several researchers have demonstrated in laboratory experiments and field applications that reducing the concentration of salts and the content of multivalent cations in the injection water may increase oil recovery. This study evaluates the performance of low salinity water injection (LSWI) in oil recovery using a crude oil and synthetic formation water of a sandstone reservoir in northeast Brazil. Two Botucatu sandstone core samples of 6 in of length and 2 in of diameter were used for the coreflooding experiments. The fluids used included a light crude oil sample, and synthetic formation water (SFW) produced from the four main salts of the original formation water (NaCl, KCl, CaCl2, and MgCl2). In Core 1, two injections were carried out at an average reservoir temperature of 60 °C, one using SFW with 200,000 mg/l as secondary recovery mode, and one using SFW diluted 40 times (40xd_SFW) resulting in a low salinity water of 5,000 mg/l as tertiary recovery mode. In Core 2, 40xd_SFW was injected at the same temperature to compare the high and low salinity water effects in the secondary mode. Moreover, zeta (ζ) potential measurements on Botucatu sandstone powder were performed in 6 dilutions of the SFW and deionized water. The experimental results demonstrated an increase in oil recovery and pH when 40xd_SFW was injected in secondary and tertiary modes. The effluent ionic concentration from Core 1 showed the reduction of Ca2+ during HSWI, indicating its adsorption on the rock surface. Most remarkably, Ca2+ concentration increases and the Na+ concentration decreases in the effluent samples in the first LSWI pore volume injected, which suggested ionic exchange of calcium for sodium on the rock surface. Furthermore, Fe2+/Fe3+ and traces of Al3+ were observed in the effluent demonstrating the occurrence of fine migration in SFW and 40xd_SFW. The magnitude of negative ζ potential on Botucatu sandstone increases as the salinity of the brine solutions decreases. Based on that experimental study, it is noticed that a set of LSWI mechanisms occurr simultaneously in Botucatu sandstone, and oil and brine samples from Recôncavo Basin, indicating a potential of application for LSWI in similar Brazilian oil reservoirs.
A Critical Review and Future Trend on Relative Permeability Hysteresis
Authors: Elhaj Murtada , Hashan Mahamudul , Hossain M. Enamul
Published: June 2018

The term "hysteresis" has been used for a long time. The researchers were paying attention because of its wider usages in many disciplines of science and engineering. However, the concept of hysteresis may differ from one discipline to other depending on parameters of interest. The effect of hysteretic on reservoir performance can be either negative or positive. Therefore, evaluation of hydrocarbon recovery techniques will depend on the accurate estimation of the rock and fluid properties. Many researchers believe that hysteresis behaviour in rock properties is related to the concept of unrecovered hydrocarbon. Numerous experimental and mathematical studies are offered to understand the hysteresis of rock properties. However, researchers paid more attention to the relative permeability hysteresis because of its important contributions on mobility ratio toward the oil recovery. The purpose of this paper is to extensively review, discuss and analyze the fundamentals of experimental processes and mathematical models of relative permeability hysteresis. In addition, the importance of relative permeability hysteresis in reservoir engineering is highlighted.

In the literature, no attempt has been made to refer and review the relative permeability hysteresis despite numerous published papers. This paper considers offering a comprehensive critical review and analysis of hysteresis that related to petroleum engineering. A systematic approach to literature survey is followed to offer a future research guideline in the area.

A critical analysis is offered on theoretical and empirical models for relative permeability hysteresis, the types of relative permeability hysteresis, factors affecting relative permeability hysteresis and rock types that are used in the experimental techniques to estimate the hysteresis. This paper tracks the current development on hysteresis and provides insight into future trends on the application of this phenomenon. The overall results show some missing concepts in existing models and experimental processes for the hysteresis. The finding also shows that for a better understanding of multiphase flow in porous media, it is essential to study the relative permeability hysteresis. Finally, this paper offers some recommendations for missing aspect and future research guidelines.

The importance of relative permeability hysteresis in fluid flow through porous media is rebuilt in describing each of the flowing phases. In addition, this study will help in understanding better reservoir performance as well as reservoir description.
Modeling of Foam-Assisted Wellbore Cleanup and Drilling Processes with Both Dry- and Wet-Foam Rheological Properties
Authors: Wang Yanfang , Thiberville Caitlyn , Kam Seung Ihl
Published: June 2018

As advanced drilling technology gains more popularity in the development of unconventional reservoirs and deepwater fields, the demand for an improved drilling hydraulics modeling escalates today. The situation is also true for foam applications that have long been used as a useful means of downhole cleaning and underbalanced drilling methods.

This study investigates how a new foam model, recently developed by Wang et al. (2017), can be applied to a wide range of hole cleaning and drilling scenarios. The model combines rheological properties of wet foams and dry foams by using 9 model parameters (3 to define the range of gas and liquid flowrates and corresponding frictional pressure losses of interest, 4 to fit the power-law rheology of wet and dry foams, and last 2 to capture the sensitivity of foam rheology to gas and liquid rates). These scenarios consider foam circulation into 10,000 ft long wells at different inclination angles with a long vertical, inclined, or horizontal trajectory. The results from this new method are compared with two existing foam modeling techniques, so-called Chen et al.'s model (based on the correlations for wet foams only) and Edrisi and Kam's model (based on wet- and dry-foam rheological properties with 5 model parameters). The results show that, with or without formation fluid influx, the new foam model demonstrates the robustness of the new modeling technique in all scenarios capturing foam flow characteristics better, whenever the situation forms stable fine-textured foams or unstable coarse-textured foams.
Realistic and Promising Technology Measures for SAGD Projects at Low Oil Price
Authors: Liang Guangyue , Liu Shangqi , Liu Yang , Luo Yanyan , Han Bin , Huang Jixin , Bao Yu
Published: June 2018

Steam assisted gravity drainage (SAGD) process is widely used in super heavy oil and oil sands projects. These projects generally have higher steam to oil ratio and poor economy, partly because un-uniform steam chamber along the horizontal section forms and it is hard to adjust, affecting by reservoir heterogeneity including muddy interlayer and thief zones. Therefore, it is desirable to explore realistic and promising technology measures for SAGD projects at low oil price.

In this paper, almost all the technology measures for SAGD projects were extensively and deeply investigated in terms of domestic and foreign reports, literatures and on-site experiences. The available research subjects include Xinjiang Fengcheng and Liaohe super heavy oil projects in China as well as ten oil sands project attached to eight corporations in Canada. Better yet, numerous statistics about technology application are reviewed well-by-well, and field application effects for some technologies were verified by deliberate numerical simulation.

Many realistic and enforceable technology measures were systematically analyzed and recommended. Single or multiple stage dilation start-up process assisted by waste water or polymer injection enhanced start-up process significantly. Infilling well pairs or wedge well, and sidetracking horizontal well or fishbone well effectively tapped the unswept remaining oil by steam. The other technologies further improved steam chamber conformance including non-condensable gas co-injection, ICD/FCD technology, differentiated operating pressure strategy, nitrogen plus dispersant foam profile control and other remedial measures, etc. Besides, the present situation and foreground application were summarized and evaluated for several promising new technologies to be studied such as screening low cost mixed solvent to increase solvent recovery, warm solvent gravity drainage (Nsolv) process and in-situ upgrading process assisted by electrical heater or catalytic modification to reduce the capital cost of surface facility, etc.

The paper contains some previously unpublished data of practical experiences, and the findings of this investigation add to the knowledge base information related to improving the SAGD performance and economy of super heavy oil or oil sands projects.
The Geochemistry and Exploration Plays Hidden in Royalty Lease Evaluation Distillation Data of Trinmar Oils
Authors: Paul Simon , Archie Curtis , Gallai-Ragobar Nancy
Published: June 2018

Royalty Lease Evaluation (RLE) distillation analysis was performed on six hundred (600) wells in Petrotrin's Soldado acreage. This data has been traditionally generated for use by Petrotrin's refinery to determine if the crude oil feedstock is compatible to the refinery configuration or if the crude oil could cause yield, quality and production problems. These made for refinery reports have become part of Petrotrin's legacy data. The authors decided to examine this dormant dataset to ascertain what hidden stories it may tell about the oilfields from which they came.

In this investigation no data is generated, but an existing and dormant dataset will be analysed. Several components in a RLE distillation report on crude oil samples will be observed for trends, patterns and relationships. Ternary diagrams and cross-plots will be employed. Specific geochemical revelations from the RLE data will be validated by comparison to conventional gas chromatography data.

This investigation will illustrate how evaporative fractionation, which is a later charge of light hydrocarbons mixing with an emplaced biodegraded oil is evidenced by a phenomenon called the" Gas Oil Anomaly", seen in the RLE data. Essentially this is the absence of any gas oil fraction combined with the presence of light hydrocarbons in the distillation data. It will also be demonstrated that presence of the later charge of light hydrocarbons has been the key factor in the prolific production from the Soldado reservoirs.

Additional analysis of the light oil and gas oil fractions of a crude oil will reveal properties and characteristics that suggest there were different sources for both the originally emplaced oils and the later charge of light hydrocarbons. The data also shows that due to the evaporative fractionation phenomenon there is no correlation with API Gravity, oil viscosity, Sulphur content and depth of the reservoirs in Soldado. It will also be demonstrated that the data can be used as a qualitative tool leading to exploration plays in the Soldado acreage.

Explorationists at Petrotrin will find the results of this investigation to be both useful and provocative as it directs their attention to specific Trinmar Soldado oilfields as deep exploration play areas in a manner that traditional geochemical analyses have not been able to. It also allows the practioners in the Petrotrin Soldado acreage to better understand the productivity and complex fluid distributions in the Soldado reservoirs.
An Integrated Method for Forecasting Well Deliverability in Gas Condensate Reservoirs with Bottom Aquifer Drive
Authors: Ellafi Abdulaziz , Flori Ralph , Dunn-Norman Shari
Published: June 2018

Gas condensate reservoirs constitute a significant portion of global hydrocarbon reserves. In these reservoirs, liquids develop in the pore space once bottomhole pressure falls below dew point. This results in the formation of a liquid bank near the wellbore region which decreases gas mobility, which then reduces gas inflow. In such complex reservoirs, it is important to correctly describe PVT impacts, adjustments to well test analysis and inflow performance, and then combine all effects in the reservoir analysis. The literature contains many references to individual adjustments of PVT analysis, well testing, or inflow performance for gas condensate reservoirs, but few studies demonstrate the complete workflow for reservoir evaluation and production forecasting in gas condensate fields. This research uses a field case study to demonstrate an integrated workflow for forecasting well deliverability in a gas condensate field in North Africa.

The workflow incorporates a description of the retrograde behavior that impact the well deliverability. The workflow begins with the interpretation of open-hole log data to identify the production interval net pay and to estimate petrophysical properties. A compositional model is developed and matched to actual reservoir fluids. Several gas condensate correlations are used to obtain the gas deviation factor and gas viscosity in order to count the change in gas properties with respect to pressure. Transient pressure analysis is described and used to identify reservoir properties. Inflow performance relationships (IPRs) are analyzed using three types of back pressure equations. The workflow integrates all data in a numerical simulation model, which includes the effect of bottom water drive.

Results show that in this field case study, reservoir behavior is composite radial flow with three regions of infinite acting radial flow (IARF). Using compositional simulation, it is found that the fluid sample for this field is a lean gas condensate since the liquid drop-out represented 1% of the maximum liquid drop-out. In addition, liquid drop-out increases by 0.1% for every 340 psi drop in reservoir pressure, which reduces the AOF by 3.4%.

The results provided in this case study demonstrate the importance of an integrated workflow in predicting future well performance in gas condensate fields. The study demonstrates how to implement the workflow in managing or developing these types of reservoirs.
Extended Reach Wells in Unconsolidated Sands in Bolivia
Authors: Dordoni Gabriel
Published: June 2018

The objective of this Technical Paper is to show the experiences and challenges in the design and execution of an extended reach well in unconsolidated sands carried out by Pluspetrol Bolivia Corporation in the Tacobo-Curiche Area. Due to surface obstacles (bed of the Rio Grande river) was proposed the drilling of a directional well which trajectory had to pass through two objectives: 1570 m Horizontal Displacement (HD) at 770 mTVD and 2345 mHD at 1171 mTVD, with the following conditions: 1st.- unconsolidated sands, 2nd.- channel of the river and 3rd.- superficiality of the objectives.

The main objectives set for this project were: Reach the targets in the required position.Provide well quality to obtain reservoir data.Provide a well capable of being tested and produced in multiple thin layers of reservoir.

These objectives raised technical challenges in different areas of well construction, i) curve construction in the first section with significant Dog Leg Severity (DLS) in well of 17½" and in unconsolidated sands, ii) complex trajectory type "S" with HD/TVD ratio> 2; iii) collision with existing well; iv) well stability and v) cementing job for high angle well, with long areas of interest and interspersed water levels.

To face these challenges, it was necessary to achieve a balance between hole cleaning, bit hydraulics, Rate of Penetration (ROP) and BHA directional response, being of vital importance for this, thixotropic mud, its density and the management of drilling parameters.

The challenges and the way to face them will be developed in this Technical Paper together with the results obtained.
The Casing Deformation During Shale Gas Hydraulic Fracturing: Why it is so Serious in Weiyuan-Changning, China?
Authors: Zhao Chaojie , Li Jun , Liu Gonghui , Zhang Hui , Wang Chao , Ren Kai , Zhang Xin
Published: June 2018

Casing deformation turned out to be serious during hydraulic fracturing of shale gas wells in Weiyuan-Channing, where the ratio of casing deformation was more than 30%. Nevertheless, there were no such phenomenon in America and other shale gas producing areas. Why there were so many horizontal wells casing deformation in Weiyuan-Changning, China? There maybe kinds of factors.

The authors mainly analyze the effect to casing deformation from operations factors during well drilling and completion, including dogleg angle, loss of cement sheath integrity and APD effect; as well as effect the geologic characteristics such as faults and natural fracture zones, lithologic interface, shale bedding.

The results show that: Firstly, though the casing strength gradually decreased as the dogleg angle increasing, the casing collapsing strength drops off only 3.8% with average 2.7°/30m dogleg angle in the casing deformation zone, which showed that it can not lead casing deformation directly. Then, though the influence of temperature and loss of cement sheath integrity will significantly reduce the safety factor of the casing, it cannot be excluded that the local cement sheath can be always damaged after hydraulic fracturing, which suggested the APD effect was not the main factor leading to casing deformation. Finally, the original stress balance near wellbore can be destroyed during multistage hydraulic fracturing leading to non-uniform in-situ stress, which can active the fault, natural fractures, lithologic interface, shale bedding to slip. Therefore there were high probability of casing deformation in the formation with faults, natural fracture zones and strong heterogeneity.

The above analysis can be used to explain why there is serious casing deformation in Weiyuan and Changning of China. Perforating far away from the point where casing deformation occurred easily and design the proper fracturing scheme can help us avoid casing deformation rather than simply raising steel grade and wall thickness of casing.