bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing the Cement Quality Using Polypropylene Fibers
Authors: Ahmed Anas , Gajbhiye Rahul , Elkatatny Salaheldin , Kalimur Rahman Muhammad , Sarmah Pranjal , Yadav Prahlad 
Published: June 2018

Abstract
With the high global demand of oil and gas, oilfield companies are seeking resources in the unexplored areas by drilling wells to explore the potential reserves of oil and gas. The drilling process has become more challenging in these unexplored areas, especially at the high pressure and high temperature conditions (HPHT). A strong cement sheath is highly desired to ensure the durability and integrity of the wells to overcome these challenges. The cement slurry design and cementing job become more challenging especially when the process is carried out at the high pressure and high temperature conditions. Industry is always looking for the new material which can be stable at these extreme conditions and meet the requirement effectively and economically.
Polymer fibers are being used in the petroleum industry lately to assist in meeting these tough requirements. In this research, the usage of polypropylene fibers (PPF) on enhancing the oilwell cements properties at high pressure and high temperature (HPHT) were evaluated. The polypropylene fibers were added into cement admixture with discrete amount to evaluate its influence on enhancing the performance of cements especially those relate to the toughness.
Experiments were performed using distinct cement slurry characteristics such as rheological properties, thickening time, compressive strength, density, porosity and permeability. The Scanning Electron Microscope (SEM), and X-ray powder diffraction (XRD) was also performed for analyzing the microstructure of the cement.
The experimental tests showed that addition of fibers improves the mechanical properties, accelerates the thickening time, reduces the porosity and permeability and helps in designing a new cement slurry which withstands the HPHT conditions. Polypropylene fiber has a significant effect on reducing the porosity and the permeability of the base cement. Microstructural analysis showed that polypropylene fiber particles block the capillaries by filling the pores in the cement, so a dense cement structure is achieved.
Steam-Foam Assessment Using Native Cores from the Ratqa Lower Fars RQLF Heavy Oil Reservoir in Kuwait to De-Risk Field-Scale Deployment
Authors: Al-Murayri Mohammed Taha , Hassan Abrahim Abdelgadir , Kamal Dawood Sulaiman , Batôt Guillaume , Cuenca Amandine , Butron Jessica , Kantzas Apostolos , Suzanne Guillaume 
Published: June 2018

Abstract
Foam has been extensively investigated as a method to improve the mobility control of non-condensable gases in the EOR context. Recently, there has been renewed interest in foam applied to steam injections. However, steam is a condensable gas and thus steam-foam requires special analyses that differ from classical foam assessments. This work presents the coreflood results of a steam-foam process evaluation for the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait.
Using specifically designed foaming surfactants, coreflood tests in the absence and presence of heavy crude oil are performed in native sandpack cores under RQLF reservoir conditions (220°C; 360 psi). In order to limit steam condensation due to the build-up of the foam pressure, steam has been supplemented with a small amount of non-condensable gas (nitrogen, about 1 - 5 mol.%). Interstitial velocity was decreased from 40 ft/day down to 1 ft/day (CWE). Phase equilibria at the core inlet were estimated based on thermodynamics flash calculations. From these calculations inlet steam quality was varied from 10 to 70 wt.%. In absence of oil, the apparent viscosity of the generated steam-foam is measured between 25 and 50 cP, depending on the interstitial velocity and inlet steam quality. Indeed, beside the classical shear-thickening behaviour observed with the decreasing flow rates, the critical or optimal steam quality is found to be closed to 30 wt.%. Furthermore, even at higher steam quality the foam is still stable and efficient with a viscosity higher than 25 cP. Experiments in the presence of crude oil were carried out under the same conditions in native cores at a steam residual oil saturation of 7% and 13%. These experiments showed that the optimal steam quality is shifted to approximatively 10 wt.%. Furthermore, the foam flow curve shows a shear-thinning behavior that is elaborated upon. Finally, the viscosity in the presence of heavy crude oil of the generated steam-foam is within the range of 7 to 22 cP, depending on the oil saturation and on the injection conditions. Considering the oil viscosity (2 to 3 cP) under the same conditions, this means that the foam effect should translate into efficient improved conformance control of the steam within the reservoir.
For the first time, an efficient and stable steam-foam is generated in coreflood experiments. The generated foam achieved high apparent viscosities, even in the presence of oil, and this has not been reported in the literature to date. The results presented here are far more than a proof of concept as they bring new evidences regarding steam-foam efficiency and mechanisms with heavy crude oil.
Determination of Particle Shape and Size Distribution from Micro X-Ray CT Scans for Petrophysical Evaluation and Sand Control Design
Authors: Ghasemi K. , Mahmoudi M. , Roostaei M. , Fattahpour V. , Soroush M. , Nouri A. 
Published: June 2018

Abstract
Particle size, shape and mineralogy are considered as primary characteristics of sand and sandstone. Several techniques have been developed for the particle size and shape analysis of unconsolidated sands. However, few of these techniques can be used for sandstones. Most particle size measurement techniques provide a spherical equivalent of the particle size and neglect the particle shape. Although several techniques have been developed for the particle size and shape analysis of the unconsolidated sands, these techniques could not be used for the size and shape variation analysis of consolidated or semi-consolidated sandstone.
Recently, X-ray micro CT scanning technique has been used for the evaluation of petrophysical properties of sandstones. This paper presents a workflow for the measurement of particle size and shape of sandstones. This research utilized X-ray micro CT scans for 2-dimensional particle shape measurements including Sphericity, Convexity, Aspect Ratio and Feret diameters. The methodology presented in this paper is the first step toward assessing the particle shape and size variation of sandstones for use in such applications as sand control design.
Image-J, an Open-source software, was used to process and filter the X-ray raw images. A new tool was developed to measure the shape factors (i.e. Sphericity, Aspect Ratio and Convexity) and size variations. A series of images from different sandstones were analyzed and compared to their lab measurements. The image calculated porosity and permeability showed some degree of deviation from the lab measured porosity and permeabilities.
This paper presents a new workflow to measure the particle size and shape for the sand control design in sandstone reservoirs. With a larger database it is possible to develop a correlation to calculate rock properties from image size analysis technique and correct them for the shape variation. The next step will be to measure the 3D size and shape from the image analysis and compare to the shape and size analysis from dynamic image analysis.
Integrity Failure of Cement Sheath Owing to Hydraulic Fracturing and Casing Off-Center in Horizontal Shale Gas Wells
Authors: Liu Kui , Gao Deli , Dahi Taleghani Arash 
Published: June 2018

Abstract
The sustained casing pressure (SCP) in shale gas wells caused by cement sheath failure can have serious impacts on safe and efficient gas production. Although horizontal wells are widely used for production from Shales, the cementing quality and casing centericity is barely ensured. Among other indications, the casing off-center is iedtified very often in the wells with SCP problem in Sichuan field. Hence, the objective of this study is to analyze the effect of the casing off-center on the integrity of the cement sheath. To better understand stress distribution in eccentric cement sheaths, an analytical model is proposed in this paper. By comparing the results of this model with the centeric casing, the impacts of casing off-center on integrity of the cement sheath is analyzed. During the fracturing treatment, the casing off-center has little effect on stress in the cement sheath if the well is well cemented and bonded to the formation rock. But on the contrary, the casing off-center has serious effects on stress distribution if the cementing is done poorly. The debonding of casing-cement-formation interfaces can significantly increase the circumferential stress at the cement sheath. At the narrow side of the cement sheath, the circumferential stress could be 2.5 times higher than the thick side. The offset magnitude of the casing eccentricity has little effect on the radial stress in the cement sheath but it can significantly increase the shear stress. We found that the risk of cement failure may reduce by making casing string more centralized, increasing the thickness of casing. The results provide insights for design practices led to better integrity in shale gas wells.
Radial Permeability Measurement for Shale Using Variable Pressure Gradients
Authors: Fan Kunkun , Sun Renyuan , Elsworth Derek , Dong Mingzhe , Li Yajun , Yin Congbin , Li Yanchao 
Published: June 2018

Abstract
Shale gas is becoming an important addition to worldwide energy supply with permeability a critical controlling factor for gas production. Helium permeability determined using small pressure gradient (SPG)methods may lead to erroneous results when applied to actual field production with variable pressure gradients (VPG). In this paper, a VPG method using real gas (rather than He) is established to render permeability measurements more representative of reservoir conditions and hence response.
Dynamic methane production experiments are performed to measure permeability using the annular space in shale cores. Boundary pressure is maintained constant within each production stage with a designated pressure gradient and the gas production with time is measured. A mathematical model explicitly accommodating gas desorption uses pseudo-pressure and normalized time to accommodate the effects of variations in pressure-dependent viscosity and compressibility. General and approximate solutions to the model are obtained and discussed. These provide a convenient approach to estimate radial permeability in the core by nonlinear fitting to match the approximate solution with the recorded gas production data.
Results indicate that the radial permeability of the shale determined with methane is of the order of of 10-6∼10-5md and decreases with an increase in average pore pressure. This is contrary to the observed change in permeability estimated with helium. Permeability errors obtained from the SPG method using helium are several times greater than those obtained from the VPG method using methane. Bedding geometry has a significant influence on shale permeability. The superiority of the VPG method is confirmed by comparing permeability test results obtained from both VPG and SPG methods.
The VPG method has two advantages: The first is that reservoir gas can be used in the VPG method instead of helium, better incorporating potential desorption impacts in permeability evltuion. The second is that realistic pressure dependent impacts can be accurately accommodated, making this method more applicable to gas production conditions in the reservoir. Although several assumptions are used, the results obtained from the VPG method are much closer to reality and may be directly used for actual gas production evaluation and prediction.
Numerical Modeling of Water-Soluble Sodium Silicate Gel System for Fluid Diversion and Flow-Zone Isolation in Highly Heterogeneous Reservoirs
Authors: Khamees Tariq K. , Flori Ralph E. , Fakher Sherif M. 
Published: June 2018

Abstract
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
Bubble Population Balance Modeling to Predict Propagation Distance of CO2 Foams in Enhanced Oil Recovery Processes
Authors: Izadi Mohammad , Kam Seung 
Published: June 2018

Abstract
A mechanistic foam modeling technique based on bubble population balance, which honors three different foam states (weak-foam, strong-foam, and intermediate states) and two steady-state strong-foam flow regimes (high-quality regime and low-quality regime of the strong-foam state), is developed to investigate how CO2 foam behaves rheologically and propagates in a petroleum reservoir. The model parameters are first obtained from a fit to existing laboratory coreflood experimental data, and then the mechanistic model is applied to different types of CO2 foams, ranging from gaseous to supercritical CO2 foams, represented by various mobilization pressure gradients.
The results from the fit to existing coreflood data show that a reasonable match can be made satisfying multiple constraints such as hysteresis exerted by three foam states, non-Newtonian flow behavior caused by gas trapping and shear thinning rheology, and bubble stability at different capillary pressure environments. Among different sets of input parameters resulting in equally nice fits, an additional experimental data (for example, the onset of foam generation by increasing the total flow rate step by step at fixed foam quality) can help narrow down the range of input parameters further. When applied to field-scale scenarios, supercritical CO2 foams requiring low mobilization pressure gradient propagate much further than gaseous CO2 foams, far enough to make use of supercritical CO2 foams promising in the fields. This in turn proves theoretically why supercritical CO2 foams should be preferred in the field compared to gaseous CO2 foams. The model shows foams in the low-quality regime can propagate longer distance than foams in the high-quality regime because of better foam stability at lower capillary pressure environment.
A New Kind of EOR for Trinidad
Authors: Delamaide Eric 
Published: June 2018

Abstract
Enhanced Oil Recovery (EOR) has been utilized in Trinidad and Tobago for over 50 years. Most projects so far have focused on thermal as well as gas injection along with the more conventional waterfloods. In spite of that, recovery factors are still relatively low and the country's oil production has been declining for some time. Surprisingly, given the progress in chemical EOR and in particular polymer flooding in the last 10 years, these processes have not been used in Trinidad and we suggest that it might be time to consider their application. Similarly, foam has been used extensively worldwide to improve performances of gas and steam injection but has not yet been used in the country.
The situation of EOR in Trinidad will be first reviewed along with the characteristics of the main reservoirs. Then the potential for the application of chemical-based EOR methods such as polymer, surfactant and foams will be studied by comparing the characteristics of Trinidad's reservoirs to others worldwide which have seen the applications of chemical-based EOR methods.
This review and screening suggests that there is no technical barrier to the application of all these EOR methods in Trinidad. Most reservoirs produce heavy oil and are heavily faulted, but polymer injection has been widely applied in heavy oil reservoirs as well as in faulted reservoirs before, and suitable examples will be provided in the paper. Similarly, these characteristics do not present any specific difficulty for foam-enhanced gas or steam injection. The main issue appears to be the identification of suitable water sources for the projects.
This paper proposes a new look at EOR opportunities in Trinidad using conventional methods which have not been used in the country. This will help reservoir engineers who are considering such applications in the country and hopefully will eventually result in an increase in the oil production in the future.
Exploiting Water Injection Techniques for Increasing Gas Recovery in Conventional Gas Reservoirs
Authors: Rambaran Keval Darvesh , Chin Chee Fat Sarah Tammie , Layne Lugard Evans 
Published: June 2018

Abstract
Primary gas recovery for a volumetric reservoir ends when the reservoir pressure declines below the value required to flow gas to the surface at the sales line pressure. Secondary gas recovery techniques can then be employed to increase the recovery, once they are economically viable. The most common of these techniques is gas compression; but another feasible technique, which is rarely ever explored, is water injection. This paper evaluates the incremental benefit of water injection in a conventional gas reservoir when compared to gas compression.
This was achieved through analytical simulation of a retrograde gas-condensate reservoir located in the Columbus Basin off the south-east coast of Trinidad. The techniques which were applied here have been historically used in the waterflooding of oil reservoirs, and were tailored in this novel case for the use in gas reservoirs. The reservoir evaluated is a faulted sandstone formation of good quality that is divided into two hydrocarbon bearing segments. In one of the segments, production ended due to a decline in the reservoir pressure, indicating the end of primary gas recovery. Both reservoir and well modelling were done using the IPM Suite. In this paper, the scope was narrowed to focus on the application of analytical simulation as a means of quickly screening various production scenarios. Simple economic evaluations were done using the University's methodology and current economic metrics, with the operational and capital expenditures derived from offshore projects by operator companies within Trinidad.
The findings showed that while gas compression generated significantly higher internal rates of return, water injection provided similar net cash flows. Unlike gas compression, which improves the recovery by allowing the reservoir to produce at a lower tubing head pressure than the sales line pressure; water injection increases the reservoir pressure by filling the voidage space created as a result of the depletion process. Thus, the feasibility of water injection is dictated largely by the volume of water which is required, since gas is highly compressible.
The primary value of water injection as a secondary gas recovery technique stems from the use of high water rates from nearby producing wells under aquifer drive, which would otherwise be shut-in. The technique can also be managed as a water disposal option for adjacent fields, thus reducing company expenditure on treating the produced water from the wells mentioned above.
Bond Log Analysis Offshore Trinidad
Authors: Welsh Christian Paul 
Published: June 2018

Abstract
This paper analyses the results of the combined Cement Bond Log/ Variable Density Log /Radial Bond Log (CBL/VDL/RBL) tool run on 10 consecutively drilled offshore development wells by an operator during the 2015/2016 period in Trinidad and Tobago. The Bond Index (BI) is used as a quantitative criterion for measuring cement to casing bond and the VDL/RBL as a qualitative criterion for cement to formation bond. The performance of the wells after perforation is examined with the aim of highlighting the importance of a good cement job for successful production. Cement pump pressure/pump rate/cement density charts are also examined to explain cement job outcomes.
Performance of CO2/N2 Foam in Enhanced Oil Recovery
Authors: Hassan Mohamed , Gajbhiye Rahul 
Published: June 2018

Abstract
Carbon dioxide (CO2) flooding is one of the attractive enhanced oil recovery process. Although it has several advantages, it suffers from early gas breakthrough due to low mobility ratio. The early breakthrough and mobility ratio can be improved by foaming CO2 gas. But CO2 is unable to generate the foam especially at supercritical condition (1100 psi at 31.10C) which is generally found in the reservoir. The CO2 foam gets weaker and weaker with an increase in pressure. It reduces the macroscopic sweep efficiency and hence the ultimate recovery.
The difficulty of generating CO2 foam is overcome by adding N2 in a small fraction to enhance the foam generation of CO2 at supercritical conditions. This study shows how the addition of small quantity of N2 helps in generating the CO2 foam and performance of the novel CO2/N2 mixture foam in enhanced oil recovery.
The goal of this study is to evaluate the oil displacement process by a novel foam system in which the CO2 and N2 mixture constitutes the gaseous phase. The experiments were carried out by flooding the core with CO2/N2 foam by imposing the condition above the supercritical CO2. The supercritical CO2 becomes denser and unable to generate the foam. To generate foam nitrogen is added to carbon dioxide to improve the CO2 ability for generating CO2 foam at supercritical conditions.
The CO2/N2 foam performance is evaluated by comparing displacement efficiency of CO2 foam with CO2/N2 foam. In addition, the effect of foam quality by fixing the injection rate were investigated on CO2/N2 foam flooding performance.