bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessing the Effect of Micronized Starch on Rheological and Filtration Properties of Water-Based Drilling Fluid
Authors: Elkatatny Salaheldin 
Published: March 2019

Abstract
Drilling Fluids rheological properties play a vital role in controlling the success of the drilling operation. Rheological parameters such as effective (or apparent) viscosity, yield point (YP), gel strength, and plastic viscosity (PV) are very important for rig hydraulic calculations and hole cleaning efficiency. The water-based drilling fluid (WBDF) consists of a mixture of different solids and polymers which are used to optimize the rheological properties. Starch is a resistance-solid additive which is used mainly to control the filtration properties and at the same time to increase the viscosity of the drilling fluid.
The main goal of this research is to evaluate the effect of using micronized starch (1 μm) on the rheological and filtration properties of water-based drilling fluid. Field emission scanning electron microscope (FESEM) was used to evaluate the starch at different particle size. Rheological properties for the drilling fluid with different starch sizes were measured at ambient condition using Fan VG rheometer while the high-pressure high-temperature (HPHT) filter press was used to conduct the filtration experiment at 200°F.
It was noted that micronized starch (1 μm) had a vital effect on the rheological and filtration properties of WBDF. The PV of the WBDF with micronized starch was increased by 158% while the YP was increased by 125% as compared with the starch of conventional size (60 μm). The apparent viscosity (AV) was increased by 137% after reducing the starch sized to 1 μm. Adding the micronized starch for the WBDF resulted in flat rheology behavior where there is no increase in the gel strength between 10 seconds and 10 minutes. The filter cake thickness was reduced by 63% while the cumulative filtrate volume was decreased by 52% when 1 μm starch is used.
This study introduced a new drilling fluid formulation that contains a micronized starch as an additive, which will help the drilling engineers to avoid many drilling issues especially the formation damage by forming an ideal filter cake.
Fundamental Behaviors and Borehole Deformation on Wellbore Stability and Sand Production in Conventional and Hydrates-Bearing Gas Reservoirs
Authors: Wang Yarlong 
Published: March 2019

Abstract
A general formulation for a coupled Thermal-Hydraulic-Mechanical with hydrate Dissociation (THMD) system is developed and applied to sand prediction for conventional gas and gas hydrate bearing sediments (GHBS). Two-phase fluid and conductive heat flow are coupled to an elastoplastic geomechanics model. Series of solutions for simplified models are presented. Fundamental geomechanics behaviors before and after plastic yielding, sanding, and gas hydrate dissociation are defined, discussed, and simulated differently and sanding onset for both conventional gas formations and GHBS are defined by an effective plastic strain (EPS) criterion. The accuracy and reliability of the proposed conventional model are verified by comparing the model prediction with the results of hollow cylinder tests on two different types of sandstone. The advantages of using the EPS over stress-based criteria as an indicator for onset of borehole collapse and sand production are discussed. Introducing a moving gas hydrate dissociation zone (front), the fundamental geomechanics behaviour and elastoplastic deformation of the skeleton formation are highlighted. The effects on sand prediction due to the characteristics of non-linear plastic yielding criteria and gas flow in porous media are also emphasized.
Surfactant-Polymer Feasibility for a Sandstone Reservoir in Kuwait. Successful Integrated Approach from Laboratory to Pilot Design
Authors: Al-Murayri Mohammed , Hassan Abrahim , Hénaut Isabelle , Marlière Claire , Mouret Aurélie , Lalanne-Aulet David , Sanchez Juan-Pablo , Suzanne Guillaume 
Published: March 2019

Abstract
This study presents an integrated approach to design a fit-for-purpose surfactant-polymer process for a major sandstone reservoir in Kuwait. The adopted procedure is described covering core flood experiments through pilot design using a reservoir simulation tool that was calibrated using laboratory results.
The surfactant-polymer formulation design was already described in another publication (SPE-183933). In this paper, further optimization of the chemical formulation is described, including core floods to minimize the quantity of the injected chemicals while maintaining high oil recovery. Formulation robustness and its impacts on water-oil separation at the surface are also evaluated. Furthermore, reservoir simulation was utilized to design a field trial. At first, the parameters that were used to model surfactant-polymer performance were calibrated using core flood results. Then, the reservoir simulation model was used at a larger scale to identify the most appropriate injection sequence for field implementation.
The performance of the designed surfactant-polymer formulation is promising. Core flood experiments demonstrate that the injection of the chemical formulation recovers more than 85% of the remaining oil after waterflooding, while having relatively low adsorption values. The designed formulation was also found to be quite resilient to variations in divalent cations concentration, water-oil ratio and oil composition. It was noticed that rock facies heterogeneity has a limited effect on surfactant adsorption. Favorable phase behavior properties were maintained around reservoir temperature and the formulation exhibited good aqueous stability between reservoir and surface temperatures. EOR parameters including salinity-dependent surfactant adsorption, capillary desaturation and polymer-induced water mobility reduction were calibrated in the reservoir simulation model using core flood data. Larger scale reservoir simulation enabled the design of a suitable injection sequence including a main surfactant-polymer slug followed by a polymer slug. The main variables of the design, including slug injection durations, chemical concentrations and pattern size were optimized through numerous sensitivity scenarios. Using a 5-spot pattern with a spacing of 75 m, surfactant-polymer injection effects should be observed within a short timeframe of around 14 months.
This paper describes a successful approach to design a surfactant-polymer process, integrating laboratory experiments and reservoir simulation. This work paves the way for a 5-spot EOR pilot involving a major sandstone reservoir and will undoubtedly provide valuable insights for chemical EOR applications in similar reservoirs elsewhere.
Integrating Production and Formation Pressure Testers Analysis for Field Development in Complicated Carbonate Reservoir
Authors: Matar Omar , Al Janahi Ahmad , Engineer Yusuf , Ali Eyad 
Published: March 2019

Abstract
For mature oil fields with complicated reservoir architecture, reservoir surveillance is key to track reservoir performance. Reservoir surveillance may include various monitoring tools from complicated horizontal production logging tools down to regular well tests. One of the main surveillance methods is running formation pressure measurement tools such as Formation Pressure Testers (FPT) or as historically known to the industry, Repeated Formation Tester (RFT). This paper describes the use of this important tool integrated with production data to understand reservoir production and depletion behavior and hence support the Bahrain Field development plan.
A study was conducted on the Ostracod and Magwa reservoirs; complicated carbonate reservoirs in the Bahrain Field. The Ostracod Zone is a sequence of inter-bedded limestone and shale in the upper Rumaila formation of the middle Cretaceous Wasia group. It is over 200 feet thick and consists of three main units: B0, B1, and B2. The Magwa reservoir is the lower member of the Rumaila Formation. It is 120 feet thick and conformably underlies the Ostracod reservoir. It consists of three main units: M1, M2, and M3.
The main objectives of this study are:
Evaluating pressure depletion from the initial reservoir pressure for each unit in both reservoirs, which defined the existence of flow barriers in this inter-bedded complicated carbonate. Evaluating the relationship between pressure depletion in each unit and the spacing between offset wells to the FPT location. Evaluating the Ostracod/Magwa pressure depletion per unit with time. Linking the pressure depletion to the cumulative production from the area offset by the FPT data.
The results of this study helped define the depletion risk on the future infill opportunities in such complicated reservoirs. It also helped in locating highly depleted units and determining the optimal locations for the new infill wells.
Beyond Steel Casing: Detecting Zonal Isolation in the Borehole Environment
Authors: Eltsov T. , Patzek T. W. 
Published: March 2019

Abstract
Electrically resistive composite casing materials are being introduced to the oil & gas industry. Resistive casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We can determine both integrity and solidification state of the cement filling annulus behind casing. Changes in magnetic permeability influence mostly the real part of the vertical component of magnetic field. The signal amplitude is more sensitive to a change of magnetic properties of the cement, rather than the signal phase. Our simulations show that optimum separation between the transmitter and receiver coils ranges from 0.25 to 0.6 meters, and the most suitable magnetic field frequencies vary from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity and other borehole in homogeneities.
New Approach of Synergizing Advanced Well Test Deconvolution, Rate Transient Analysis and Dynamic Modeling in Evaluating Reservoir Compartmentalization Uncertainty at K Field in Sarawak Basin; A Case Study
Authors: Hj Azlan Ali Al-Amani , Wan Muda Wan Mohd , Mubaraki Alireza Hajizadeh , M Khir Khairul Ezee , M Sahid Norhayati , M Zakei Amran 
Published: March 2019

Abstract
This paper presents the result of synergizing advanced well test deconvolution, rate transient analysis and detailed reservoir modeling to answer the compartmentalization uncertainty demonstrated by downhole pressure data in K field located offshore Sarawak, Malaysia. The gas reservoir is well distributed within approximately 10 × 20 km area and divided into two fault blocks, east and west. The development only focused at eastern area. Based on earlier assessment during Field Development Plan (FDP) stage, no fault has been seen from seismic data interpretation within east area. However, the six years actual performance of the field address different understanding which suggesting possible compartmentalization. Several assumptions were made to reconcile the connected hydrocarbon initially in–place estimated from conventional material balance and static volumetric calculation, however it has led to inconclusive results. The paper draws on the strength of an integrated reservoir engineering studies that include analytical and numerical analysis. The general framework covers advanced well test deconvolution analysis which multiple Pressure Build Ups (PBUs) and flowing duration were interpreted. This helps in guiding reservoir characterization understanding further from the well and type of fault setting within the reservoir. In addition, Rate Transient Analysis (RTA) has been conducted to estimate the connected volume. Several interesting findings will be shared in this paper as well.
The combination of these deconvolution and RTA works enhanced the understanding of reservoir compartmentalization which guided the history matching process done through dynamic model. The newly established workflow has reduced the efforts required in history matching process and gave clearer picture of the uncertainty of reservoir compartmentalization.
Reservoir Pore-Throat Characteristics Evolution During Waterflooding: A Theoretical Study
Authors: Lei Gang , Liao Qinzhuo , Patil Shirish 
Published: March 2019

Abstract
During waterflooding, pore-throat structure of the porous media in the reservoir changes continually, which causes the great challenge in reservoir modeling and simulation. However, through the evolution mechanism of pore-throat characteristics for the reservoir during waterflooding has been intensively investigated in the past several decades, the essential controls on pore-throat structure evolution of reservoir rocks are not studied much. It is of theoretical and practical significance to use analytical methods to study the evolution of pore-throat characteristics of porous media during waterflooding. However, because of the disordered and extremely complicated microstructures of porous media, the theoretical model for stress sensitivity is scarce. The objective of this work is to establish a novel and reasonable quantitative model to determine the essential controls on pore-throat structure evolution of reservoir rocks. The theoretical model is derived from the fractal geometry. The predictions from the proposed model agree well with the available experimental data presented in the literature, which verified the novel quantitative model. There is no empirical constant and every parameter in the model has specific physical significance. In addition, the evolution rule for the pore-throat structure parameters has been obtained. The results show that the pore-throat structure of porous media becomes more complex and more heterogeneous after waterflooding. The pore-throat parameters (e.g. porosity, permeability, the maximum pore-throat radius, average pore-throat radius and sorting coefficient, etc.) will change during waterflooding. This work presents accurate and fast analytical models to perform the evolution rule of pore-throat characteristics of porous media during waterflooding. The proposed models can reveal more mechanisms that affect the coupled flow deformation behavior in porous media.
Palynological Correlation of the Late Cambrian to Middle Ordovician Saq Formation in Saudi Arabia and Equivalent Strata in Oman Manuscript Title
Authors: Vecoli Marco , Cesari Christian 
Published: March 2019

Abstract
The Cambro-Ordovician succession of Saudi Arabia comprises dominantly siliciclastic sediments deposited in a passive margin intracratonic setting and includes the fluvial to marginal marine Saq Formation (Late Cambrian to early Middle Ordovician), the marine Qasim Formation (late Middle to Late Ordovician) and the glaciogenic Sarah Formation (Hirnantian, latest Ordovician).
The Saq Formation is subdivided into the Risha Member (Late Cambrian) and the Sajir Member (Early to Middle Ordovician). Palynological age-control in the Risha Member is provided by a characteristic acritarch assemblage (CB1 Palynozone) which contains well-known Furongian (Late Cambrian) diagnostic taxa (e.g., Trunculumarium revinium, Timofeevia phosphoritica and Ninadiacrodium dumontii), as recorded in one subsurface locality in the Arabian Gulf. This typical assemblage occurs worldwide in Furongian-aged strata and not only permits a confident age- attribution, but also indicates an open marine facies within the predominantly fluvial to marginal marine lower Saq Formation. In Oman, the same assemblage occurs in the Al-Bashair Member of the Andam Formation. In the lower part of the Sajir Member, one acritarch assemblage characterized by the presence of Acanthodicaodium angustum and Vulcanisphaera spp., was described from a subsurface section in Eastern Saudi Arabia, indicating an earliest Ordovician (Tremadocian) age. This assemblage forms the O6 Palynozone and suggests correlation with the Mabrouk Member of the Andam Formation in Oman.
The top of the Sajir Member of the Saq Formation is characterized by mud-rich bioturbated deposits which typically yield a distinct palynological assemblage (O5 Palynozone), characterized by dominance of morphologically distinctive sporomorphs (e.g., Virgatasporites spp., various hilate sporomorphs) and characteristic acritarch species such as ?Clypeolus sp., ?Cymatiosphaera sp., ?Retialetes sp., and Barakella spp. The assemblage is also characterized by the first occurrence of some typical Middle Ordovician acritarch taxa such as Arkonia, Striatotheca, and Frankea. Among the chitinozoan, Siphonochitina formosa is typically represented. The age of this assemblage spans the Dapingian to earliest Darriwilian, in agreement with faunal evidence. The assemblage indicates a marginal marine, restricted paleoenvironment. Virtually identical palynological assemblages occur in Oman in the Saih-Nihayda Formation, considered of late Dapingian to Darriwilian age. More specifically, it is suggested here that the O5 Palynozone of Saudi Arabia permits correlation of the upper Sajir Member of the Saq Formation with the lower, sand-prone, part of the Saih Nihayda Formation in Oman.
Towards Identifying the Mechanisms of the Modified-Salinity Waterflooding by a Novel Combination of Core flooding and Mathematical Modeling
Authors: Taheri Mirhossein , Bonto Maria , Eftekhari Ali Akbar , M. Nick Hamidreza 
Published: March 2019

Abstract
Our objective is to find an alternative approach to the history matching of the modified salinity water flooding tests in secondary and tertiary mode. Instead of matching only the recovery factor and pressure drop history, we give a higher priority to matching the different ion concentrations and oil breakthrough times. Based on these analyses, we suggest the predominant mechanisms for the modified-salinity water flooding in carbonates.
The work is done in three steps: 1) Studying a large data-set of modified-salinity water flooding experiments in carbonates. 2) Quantifying the adsorption of potential determining ions (PDIs) on the carbonate surface using an optimized in-house surface-complexation model 3) Adjusting the relative permeability parameters to history-match the experimental data using different analytical solution of water-flooding (with and without ionic adsorption) combined with modern search-based optimization algorithms. The optimization algorithm gives a high weight factor to the breakthrough time of oil and PDIs.
Having too many parameters in the relative permeability (6 parameters for Brooks-Corey type) make it possible to match any type of recovery curves. However, we found out that matching the breakthrough times, especially in the tertiary modified salinity waterflooding, can only be achieved by considering the wettability change due to the adsorption of PDIs on the carbonate surface. This observation, combined with our ability to accurately model the adsorption of PDIs on the carbonate surface, helped us to identify the important PDIs that cause the wettability change in carbonates. For instance, we observe that a model that considers the wettability change due to the adsorption of calcium ions on the chalks surface matches perfectly to the tertiary flooding of the Stevns Klint outcrop chalk with seawater. The second important observation is that the lag between the start of the injection of the modified-salinity brine and the oil breakthrough time is not always due to the adsorption of ions and sometimes can be explained by the wettability change due to the lower salinity of the injected brine. It must be noted that this new approach is still semi-empirical, and needs to be combined with more fundamental studies to identify the actual mechanisms.
Enzyme Enhanced Oil Recovery EEOR: A Microfluidics Approach
Authors: Rahayyem Maher , Mostaghimi Peyman , Alzahid Yara A. , Halim Amalia , Evangelista Lucas , Armstrong Ryan T. 
Published: March 2019

Abstract
Enzyme Enhanced Oil Recovery (EEOR) has recently been categorized as one of the most effective EOR mechanisms. Laboratory and field studies have reported up to 16% of incremental oil recovery rates. EEOR recovers oil mainly by two main mechanisms: lowering the interfacial tension between brine and oil and altering the wettability on rock grains to a more water-wet condition. Therefore, EEOR would promote mobilization of capillary-trapped oil after regular waterflooding. Since capillary-trapped oil resides at the micro-scale, it is essential to assess EEOR fluid-fluid interaction at that scale. To further investigate the ways in which these enzymes contribute to EOR, an experimental micro-scale approach was developed in which EEOR was analyzed using polydimethylsiloxane (PDMS) microfluidic devices. The PDMS microfluidics device was based on X-ray micro-CT images of a Bentheimer sandstone with resolution of 4.95 μm. We first compared the IFT reduction capabilities of one class of enzyme (Apollo GreenZyme ®) and a commercial surfactant (J13131) obtained from Shell Chemicals. For GreenZyme concentrations of 0.5, 1.5 and 2 wt%, the IFT values between GreenZyme solution and oil are 4.2, 0.7 and 0.6 mN/m, respectively. Whereas the IFT values for 0.5 wt% surfactant solutions and deionized water are 1.1 and 32 mN/m, respectively. We then compared the oil recovery of the two systems using the aforementioned sandstone PDMS microfluidics device. Recovery values up to 92% of oilwere obtained using GreenZyme. Surfactant and waterflooding on the same PDMS chips had recovery values of 86 and 80%, respectively. This study provides insights and direct visualization of the micro-scale oil recovery mechanisms of EEOR that can be used for design of effective EEOR flooding.