bluuebunny/crossref_metadata_2025_split huggingface dataset:
Introduction of a Thermal Model to Analyze Pressure-Falloff Data Leads to an Accurate Pressure-Transient Analysis and a Detailed Thermal Profile of the Water Bank in an Oil Reservoir
Authors: Akresh Saud A. , Alodah Meshari D. , Guerrero Rodolfo J. , Rahman N. M. 
Published: October 2018

Abstract
Water injection into oil reservoirs is widely used practice to support oil production by maintaining the reservoir pressure within a desirable range to avoid a decline in reservoir pressure. Frequent monitoring of the water injectivity in the injection wells are very crucial to ensure meeting injection targets for an optimum level of reservoir management. Therefore, transient tests on water injection wells are an essential component in the data acquisition program of oil fields as these reveal important dynamic information about the wellbore condition and the reservoir characteristics. Usually, surface water is used for injection where the contrast in temperatures between the injected water (relatively colder) and the oil reservoir which is deep in the ground (hotter) creates a progressive colder-water bank inside the reservoir. Such a colder bank would have an effect on the injectivity of the well. Using traditional models without considering the thermal effect might result in underestimating or overestimating both reservoir flow capacity and skin damage.
In this research, we will use a thermal model to study the pressure behavior during injection and falloff periods and observe the development of a colder-water front in which its size inside the reservoir will be investigated varying different parameters, such as duration of injection history, injection rate, and reservoir permeability. In addition, we will demonstrate the impact of the cold-water front on the injectivity.
Study of OBM Invasion on NMR Logging - Mechanisms and Applications
Authors: Hursan Gabor , Ma Shouxiang Mark , Valori Andrea , Sauerer Bastian 
Published: October 2018

Abstract
Due to the shallow depth of investigation of logging tools such as Nuclear Magnetic Resonance (NMR), the signal interpretation of the flushed zone must be performed carefully. Understanding invasion effects on the logs is an important prerequisite for any petrophysical evaluation. While it is relatively easier to evaluate and correct for the effect of filtrate invasion in basic logs, such as triple combo, special care must be taken for advanced logging techniques such as NMR. For example, it is generally assumed that the volume of remaining wetting fluid in the flushed zone equals to the volume of micropores that do not contribute to flow when the well is produced. The amount of these immobile fluids is estimated using the NMR bound fluid log, a key input for the prediction of rock quality and well performance, especially in complex clastic and carbonate pore systems. In certain formations, NMR bound fluid logs exhibit some differences between adjacent wells drilled with oil-based (OBM) and water-based muds (WBM). This paper summarizes the lessons learnt from a laboratory NMR study of oil-based mud filtrate (OBMF) invasion as a function of rock mineralogy and microstructure, mud chemistry and displacement/flow pressure.
In this work, we studied the effect of a commercial surfactant usually added in OBM formulations. We investigated the effect of different surfactant concentrations on the fluid-fluid interfacial tension (IFT) properties and on the fluid-solid interaction properties, using contact angle measurements on both sandstone and carbonate model surfaces. Furthermore, we investigated the effect of the additive on the capillary pressure properties and remaining water saturations on sandstone and carbonate rocks. To maximize the generality of the results we used two very different driving mechanisms for the fluid displacement: centrifuge and flow-through.
The data showed that carbonate and clastic rocks behaved differently over a wide range of flow mechanisms and water saturations, proving that mineralogy plays a crucial role in the fluid displacement. Under the measurement uncertainties, the irreducible water saturation, however, remained constant regardless of the OBMF composition or driving mechanism.
We showed how sandstone and carbonate rocks behave in respect to wettability alteration due to a surfactant used in OBM formulations. The systematic difference, whatever the driving mechanism is, strongly suggests that the differences in NMR responses between sandstone and carbonate originate from chemical composition and surface properties rather than microstructural differences between sandstone and carbonate rocks.
BTKr_cor Methodology Provides an Improved Approach for Numerical Simulation of Vertical Water Segregation in Grids with Large Aspect Ratios
Authors: Kayode Babatope O. , Lyngra Stig 
Published: October 2018

Abstract
Vertical segregation of water is defined as the tendency of water to slump downwards in a vertical sense while undergoing a lateral/areal displacement. In reality, this phenomenon is driven by the density difference between reservoir fluids (oil, water) as well as the reservoir’s vertical permeability heterogeneity. If water is injected at one end of a hypothetical thick and homogeneous sand, the injected water would advance laterally and slump vertically as described by the 1-D Buckley-Leverette (BL) mathematical model. Aspect ratio is defined as the ratio of a grid’s lateral size to its thickness (Dx/Dz). There is the usual constraint to keep Dz as small as possible to allow the description of fine vertical heterogeneities that may be important for flow modeling, there is also the constraint to make Dx large enough to ensure a manageable total number of grids that available computational resources can handle. These constraints lead towards an increasing simulation grid aspect ratio. The purpose of this paper is to demonstrate the impact of increasing aspect ratio on the simulation of vertical segregation of water and present an improved methodology based on BTKr_cor (Kayode et.al 2017) for modelling of vertical oil- water segregation in numerical reservoir simulation. Simulation results from synthetic reservoir model cases are used.
The base-case scenario contains a hypothetical 5-spot injection pattern with 1200 feet injector-producer distance. The wells are placed in a fine-scale grid with block dimensions of 5ft x 5ft x 1ft. After one year of water injection, the simulated saturation-depth profile around the water injector was found to compare favorably with the analytical BL profile. The study included sensitivities varying (i) vertical (kv) / horizontal (kh) permeability ratio, (ii) grid-size (iii) introduction of permeability heterogeneities and (iv) the application of BTKr_cor relative permeability scaling (Kayode et.al 2017). The impact these parameters have on the simulated vertical water segregation are presented.
Simulation results demonstrate that with increasing aspect ratio, the vertical water segregation becomes more pronounced than shown by the fine-scale base case results. The use of low kv/kh values to reduce vertical segregation in large simulation grids resulted in a mismatch of up to 10 units of remaining oil saturation around the injectors. It was however found that regardless of grid size and permeability heterogeneity, the use of the BTkr_cor approach shows the best match with fine grid simulation results.
The methodology described in this publication allows improved numerical simulation of vertical segregation while respecting observed kv/kh ratio from sources like pressure transient analysis (PTA), core data, and vertical interference tests (VIT).
New Formulations for the Control of Iron Sulfide Deposits in Oil Production Facilities
Authors: Jawish M. W , Suleiman R. , Wang Q. , Chen T. , Shen S. W. 
Published: October 2018

Abstract
Tetrakis(hydroxymethyl)phosphonium Sulfate (THPS), an environmental friendly biocide, is gaining more interest as a dissolver to control iron sulfide (FeS) precipitation in oilfield production systems. In previous works, combinations of THPS and different additives, such as ammonium chloride, chelating agents or organic phosphonates, were examined for the synergistic effects of FeS scale dissolution under room and high temperatures. It was found that THPS and ammonium ion can create a purple-colored complex which can significantly improve the FeS dissolution. Studies also indicated that the synergistic effect of ammonium chloride was largely attributed to pH decrease. As a result, the corrosivity of THPS solution to metallurgy was increased. In this work, new formulations based on THPS is introduced. Chloride ions were substituted with different organic compounds. The dissolution rate of analytical grade FeS solid and carbon steel corrosion were investigated at different temperatures. The chemical composition of the undissolved FeS solid and the THPS-Amine-Iron complex structure were analyzed for the most effective dissolver formulations. The efficiency of new formulations was further evaluated using field scale samples collected from water injection pipeline and a sour gas well, and the structures of the FeS scale before and after dissolver treatment were studied to reveal the mechanism of dissolution.
A Novel Superfine Fibrous Lost Circulation Material derived from Date Tree for Seepage Loss control
Authors: Ramasamy Jothibasu , Amanullah Md 
Published: October 2018

Abstract
Lost circulation is one of the major challenges faced by oil and gas industries around the globe causing significant amount of drilling non-productive time. Loss of drilling fluid could lead to additional drilling problems such as stuck pipe, borehole instability or a potential well control event. There are different types of materials such as fibrous, flake type, particulate, etc. are available in the industry to combat loss of circulation. Superfine fibrous type of materials are used to mitigate seepage losses. These fibrous materials are derived from wood fibers. The objective of this paper is to develop an eco-friendly, biodegradable superfine fibrous lost circulation materials from date tree fibers for addressing seepage type losses. We have developed a novel fibrous lost circulation material (Arc Fiber SF) using date tree waste available locally as the raw material. Small scale crushing and grinding process were used for lab scale sample preparation. A suitable particle size distribution of the superfine materials required for seepage loss control have been achieved by sieving process. In order to demonstrate the seepage loss control ability of the superfine materials, low sold non-dispersive KCl-polymer samples have been formulated incorporating superfine fibrous materials and for comparison, a mud formulated using commercially available seepage loss control material. HPHT filtration control experiments carried out at 212 °F and 500 psi also proved the ability of these materials in reducing the amount of filtrate. This observation suggests that the date tree fiber based LCM is a suitable alternative to commercial fibrous LCMs used in the industry. The in-house product Arc Fiber SF has been developed by simple grinding and sieving process of date tree waste and has the potential to replace the commercial equivalents.
Cement Failure Modeling for High Pressure High Temperature Wells: Case Studies
Authors: Sanuade Oluseun A. , Elkatatny Salaheldin 
Published: October 2018

Abstract
Well cementing is an important operation during drilling and completion of oil wells. The cement sheath must maintain well integrity behind the casing and provide long-term zonal isolation to ensure safety and prevent environmental problems. Some of the uses of cement sheath include providing support for casing, sealing off of annulus and protection of the casing from any corrosive formation fluids that may be in the casing well. Perforation and fracturing operations could damage the integrity of the system of casing–cement–formation during production which could eventually lead to failure. The problems of well cementing still persists despite advancements in technological development of cement and concrete materials. Moreover, changes in temperature and pressure during the life cycle of the well can give rise to several mechanisms of failure that could pose threat to the set cement sealing integrity. Therefore, crucial models are important to understand the behavior of cements at different conditions and hazardous outcomes of cementing failure. The objective of this paper is to review the available failure models for cement and illustrate the main causes of cement failure for actual field cases. This review provides an overview of the five cement failure models including analytical, finite element, probability, thermo-poro- elasto-plastic and buoyancy-driven models. The theory and applications of these models are discussed. Probable solutions to cement failure were also reviewed. This review will help to have proper understanding of the vulnerability of mechanisms of cement sheath failure to changes in important properties of a casing-cement-formation well section when subjected to different well operation conditions. The novelty of this work is the deep investigation of the failure mechanics of different cement slurries in addition to supporting the main conclusion of this work by actual case studies.
Estimating Zonal Gas Contribution Using DST Gas Composition Parameters
Authors: Aijaz M. Jahanzaib , Hameed Khalid , Ahsan Omer 
Published: October 2018

Abstract
Individual contribution from each zone is of vital importance in wells producing from different zones from a single tubing string. Zonal production volumes are important for reserves evaluation as well as future projection with respect to processing facility. Gas analysis obtained during production phase when compared to those obtained during Drill Stem Tests can give valuable information regarding zonal contribution.
Monitoring of production parameters can allow to develop a method based on thorough analysis of DST results to predict specific contribution from each zone. Bifurcation of commingled flow was based on the gradual change in key gas composition parameters. Both zones were initially tested separately and gas samples were collected and analyzed at surface. During testing, CO2 mole percentages from Reservoir 3 and Reservoir 2 were measured as 8 mol% and 5 mol% respectively. When well started commingled commercial production, initial CO2 concentration was recorded as 7.67 mol%. Factors were selected which when multiplied with initial CO2 concentrations gives the recorded CO2 concentration. The factors are the fractional gas contribution from each zone. Gradual decline in CO2 concentration suggested that the contribution from Reservoir 2 has increased over time. Results obtained by distributing the compositions received from production data according to the results obtained during well test analysis were matched by using iterative methods. Based on individual compositional contribution, volumetric contributions were attributed to each zone. Results predicted from this method were in close agreement with the results obtained from down hole logging survey performed later. Method used is general and can be applied to any well with similar characteristics. It can also be extended for three zones producing from same tubing string and reliable data from well testing is available. This can eliminate the costly requirement of down hole logging survey, production loss and risks related to well interventions.
A simple yet holistic method was developed for estimating zonal contribution if reliable well test gas composition data is available. The data was compared with production data and based on the gas composition mix, zonal contribution was attributed which was also verified by down hole logging survey.
High Resolution Analysis of Sand-Based Composition for Hydraulic Fracturing Application
Authors: Al-Hulail Ibrahim , BinGhanim Ahmed , Abdulrazzaq Waseem , El-Hajj Hicham , Abdullatif Osman 
Published: October 2018

Abstract
The application of liquid resin in hydraulic fracturing helps to increase hydrocarbon production by improving conductivity, controlling proppant flowback, inhibiting fines migration, and reducing sand production. This study compares natural sand and proppant in terms of the grain-to-grain relationship (texture) of coated and uncoated samples and describes how microfractures, micropores, and grains are filled and encapsulated by liquid resin.
During proppant placement, the concentration of the resin can delay the curing time, which induces consolidation of the proppant pack in the fractures. By extending the curing period, there is more time for the proppant to develop grain-to-grain contact in the fracture as well as for capillary action to pull the liquid-resin coating to the contact points of the proppant grains, thereby providing a highly cohesive consolidated proppant pack. The resin concentration used falls within the oilfield industry’s applicable practices. Several evaluation techniques were used to understand the crystallinity and morphology of coated and uncoated sand/proppant. These techniques included thin section petrography, scanning electron microscopy (SEM), and geomechanical tests.
Photomicrographs analysis and SEM images have shown the presence of a very large amount of monocrystalline quartz in the uncoated sand samples, which also displayed reduced mechanical strength as a result of microimperfections in the uncoated sand. A comparative study showed that after resin coating the angular and microfractured sand, mechanical properties of the angular and microfractured sand improve as a result of enhanced interlocking effects of this type of sand.
This paper provides a qualitative description of the variation in coated and non-coated sand/proppant in terms of grain-to-grain contact. Moreover, the study also hypothesizes how resin-coated sand can help to fill in micropores and microfractures.
Application of Integrated Reservoir Geomechanics for Well Planning of High-Angled Wells in a Mature Oil Field
Authors: Abbas Ahmed K. , Flori Ralph E. , Al-Asadi Yousif M. , Alsaba Mortadha , Al-hamad Nasser A. 
Published: October 2018

Abstract
Zubair oil reservoir has a significant potential to contribute to the petroleum supply in Iraq. Drilling highly-deviated wells is a commonly used approach to enhance the production in mature fields. Drilling these wells in the Zubair Formation has been a challenge due to severe wellbore instability issues. This study presents how integrated reservoir geomechanics was used for efficient well planning and safe drilling of nearly horizontal wells (75° Inclination) through Zubair depleted sandstone oil reservoir.
In this study, an integrated workflow was implemented mainly to build a geomechanical model using offset well data. The in-situ principal stresses and their orientations were obtained from wireline logging measurements and mini-frac tests. The repeat formation test (RFT) was used to constrain pore pressure. Rock mechanical properties were calculated using empirical correlations that have been derived from laboratory tests on core samples. Mogi-Coulomb failure criteria was used to address safe mud weight for drilling highly-deviated wells successfully. The model was verified with wellbore failure and also with wellbore instability events while drilling operations.
The results obtained from the geomechanical model shows that Zubair sections of planned wells would have narrow mud weight windows. The analyses also emphasized that the shale interbeds in the Zubair section require a mud weight of 1.5g/cc to limit wellbore breakouts. The presented study highlights that the geomechanical model can be applied as cost-effective tools to assess and address existing wellbore instability problems and to guide future well plans for better drilling efficiency with a reduced non-productive time (NPT) by using proper mud weight with respect to the inclination angle and the azimuthal direction.
Developing an Efficient Drilling System by Coupling Torque Modelling with Mechanical Specific Energy
Authors: Hassan Amjed , Al-Majed Abdulaziz , Elkatatny Salaheldin , Mahmoud Mohamed , Abdulraheem Abdulazeez , Nader Mahmoud , Abughaban Mahmoud , Khamis Mohammed 
Published: October 2018

Abstract
Understanding the formation behavior and the drilling operation is essential to optimize the performance of drilling systems. Several studies were conducted to improve the drilling operation in real time basis utilizing different approaches. Numerous mathematical models (analytical or empirical) were developed to relate the drilling parameters with the rate of penetrations and to predict the drilling efficiency. However, these models are arrived at by ignoring some parameters or employing simplifying assumption(s), which may lead to over or under optimistic drilling performance.
The main objective of this research is to investigate the analytical and numerical approaches to calculate the torque and drag in drilling operations and produce a simple and robust model using artificial intelligent techniques. More than 22,000 data point from several wells for depth up to 18,000 ft. was used to develop and validate the model reliability. The full profiles of torque and rate of penetrations was determined, also the required energy for drilling each section has been estimated. The developed model could be utilized to define the optimum range for torque, which leads consequently to generate an efficient drilling system and reduce the drilling cost.
In this study, rate of penetration (ROP) was determined using the torque profile and mechanical specific energy (MSE) based on real time and rig-site data. Statistical analysis was conducted to understand the importance of drilling parameters on the variations of torque and rate of penetration. Drilling parameters such as weight on bit (WOB), revolution per minute (RPM), fluid circulation rate (Q), and bit hydraulic horse power (HPb) has been studied. Thereafter, artificial neural network (ANN) model was developed to predict the torque and ROP profiles. The suggested models enable the drilling engineers to optimize the drilling parameters in a real-time manner, by changing the surface and controllable parameters in such a way that maintains the drilling operations within the optimum conditions. This research will assist in improving the operations efficiency through optimizing the drilling parameters. A strong robust model was developed which yields high accuracy results when compared with actual field measurements, average absolute percentage error of less than 6.5% was achieved.