bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing the Gel Strength of Water-Based Drilling Fluid Using Clays for Drilling Horizontal and Multi-Lateral Wells
Authors: Alakbari Fahd , Elkatatny Salaheldin , Kamal Mohamed Shahrazad , Mahmoud Mohamed 
Published: October 2018

Abstract
Drilling fluid constitutes an important part of the drilling operations. Drilling mud is circulated into the wellbore to minimize the formation damage, transport cuttings from the bottom to the top of the well, cool and lubricate the bit, and maintain the stability of shale formations. Gel strength property of drilling fluids plays a key role in drilling multilateral and long horizontal reservoir sections. Losing the gel strength will accumulate drilled cuttings and as a result, sticking of the drill string. Solving this issue takes a long time and increase the total cost of the drilling operation. It was observed that, by increasing the temperature to 200°F, the gel strength of calcium carbonate water-based drilling fluid reached zero lb/100 ft2.
The objectives of this paper are to: (1) determine the rheological properties of calcium carbonate water- based drilling fluid over a wide range of temperature, (2) assess the effect of using clays (bentonite) to solve the gel strength problem associated with the current field formulation of calcium carbonate water- based drilling fluids, and (3) optimize the weight percent of bentonite. Rheological properties such as the apparent viscosity, plastic viscosity, yield point and gel strength were measured by using a high-pressure high-temperature rheometer.
At low temperatures (85°F), the calcium carbonate water-based drilling fluid showed no change in the gel strength with time. However, at high temperatures, the gel strength starts decreasing with time. Rheological properties confirmed that the gel strength of the calcium carbonate water-based drilling fluid reached zero lb/100 ft2 by increasing the temperature to 200°F. This issue was solved by adding different concentrations of bentonite. The bentonite concentration was varied from 3 wt.% to 10 wt.%. At low bentonite concentrations (3.33 wt.%), the gel strength still reduced with time. At high bentonite concentration (10 wt.%), the gel strength increased with time. The optimum concentration of bentonite was 6.66 wt.%, which yielded a flat rheology profile of the gel strength. These results confirmed that the rheological properties of the water-based drilling fluid were optimized by using clays (bentonite).
The novelty of this research is the complete investigation of the drilling fluid properties especially the gel strength with time over a wide range of temperature. The results obtained can leads to the development of a cheap solution without any side effect.
A Generalized Varying Oil Compositions and Relative Permeability Screening Tool for Continuous Carbon Dioxide Injection in Naturally Fractured Reservoirs
Authors: Hamam Hassan , Ertekin Turgay 
Published: October 2018

Abstract
Carbon Dioxide (CO2) injection is a viable technique with huge potential if employed efficiently in naturally fractured reservoirs. However, extensive computational resources are needed to evaluate and consider candidates for continuous CO2 injection projects. In this study, a new workflow is developed that captures universal fluid compositions and relative permeability data for fields undergoing continuous CO2 injection in naturally fractured reservoirs.
Injection design schemes and parameters for continuous CO2 for hypothetical reservoir types are constructed using a miscible, dual porosity, compositional reservoir simulation model. An algorithm is developed to capture varying fluid compositions and relative permeability data for the data set used in this study. Data collected from reservoir simulation cases are used to construct two Artificial Neural Network (ANN) based proxy models. Namely, a proxy for performance prediction that utilizes specific injection design parameters to predict reservoir performance and an inverse proxy for injection design that provides injection design scheme for a desired reservoir performance.
The constructed ANN’s predictability is assessed through its capability of predicting blind test data within a specified tolerance. The proxy based models were capable of predicting, within an acceptable degree of error, the oil and gas production profiles as well as injection design parameters of well spacing, CO2 injection rate, and CO2 injection duration of a field undergoing continuous CO2 injection. The constructed networks were tested with real data from Twofreds field in Texas that has been undergoing continuous CO2 injection since 1974. The constructed proxy based models were able to overcome limitations imposed by the complexity of handling different compositional reservoir fluids and relative permeability data. The new methodology sets a new benchmark for universal proxy modeling as it incorporates composition based reservoir fluid and relative permeability data.
The approach presented overcome existing limitations in handling compositional reservoir fluid variations as well as relative permeability in universal workflows.
Surmounting Paucity of Data in Hydraulic Fracture Designs: Case Studies From the Permian Basin
Authors: Elsheikh Ellewa Ahmed , Amao Abiodun Matthew 
Published: October 2018

Abstract
The design of an optimal and effective hydraulic fracture treatment requires lots of input data, spanning the spectrum from rock properties, fluid properties, well-logs, Geomechanics to economics. However, operators tend to cut costs by reducing expenditure on data acquisition. This paper discusses the challenges of hydraulic fracture treatment design in such cases and presents procedures that can be used to effectively design fracture treatments where completion engineers may not find the needed data from obvious direct sources. Recommended solutions for obtaining data from indirect sources to fill the gap of unavailable data are presented. In addition, the adequacy of such designs is evaluated and compared to actual hydraulic fracturing treatments pumped.
Treatment designs pumped for several stages of a fractured well located in the Permian Basin of West Texas, US were investigated. This is a geologically complex environment with huge variation in lithology and formation properties. The well under study had only the drilling records and the conventional logs suite (gamma ray, neutron, density, pe and resistivity). However, to finalize other required data for the treatment design i.e. reservoir permeability, geomechanical properties, etc., the design inputs were obtained through the creation of synthetic logs. Sonic logs were generated using models created from log data from off-set wells. In addition, geological properties of the candidate formation were reviewed and used for data calibration. These collected data were then used in designing the hydraulic fracture treatment using industry standard fracture design software, FRACPRO, to obtain the design outcomes. The treatment was designed and simulated using the same fluid systems and proppants as was used in the actual pumped treatments. Finally, the design results were compared to the field treatment data from the fractured well.
Compared to real-time fracturing results, the pressure and rate profiles were close match to those generated by the software. This shows the possibility of conducting a proper fracturing design using limited acquired data. However, these results depend mainly on the accuracy of the well logs used to generate the mechanical properties, and the available data about the formation from previous treatments. Moreover, the accuracy of fracturing simulation when all needed data are obtained by direct measurements should be compared to situations with paucity of data, to determine how to improve the results obtained.
The information presented in this work will help engineers deliver economic and optimal hydraulic fracture treatments especially in this present low oil price regime. Also, informed and appropriate decisions can be made regarding optimized data acquisition in candidate formations for better planning and maximum profitability.
Natural Fractures Permeability in Liquid Reservoirs During Non-Darcy Regime
Authors: AlSinan Marwah 
Published: October 2018

Abstract
Fluid flow in Fractures is the main transport and production mechanism in naturally and hydraulically fractured reservoirs. Thus, understanding the various non-Darcy flow regimes is critical for naturally fractured reservoirs, particularly for gas and near the wellbore. While the Forchheimer model for non- Darcy flow has been confirmed numerously, models describing flow behavior prior to the Forchheimer model are still controversial. Also, since the conductivity of a fracture network is dependent on the permeability of the individual fractures, the relationship between fracture transmissivity and morphology requires investigation.
In this paper, a systematic analysis of experimental data, spreading over a vast range of Reynolds number (Re), was carried out to assess the encountered flow regimes. The analysis was conducted using three diagnostic plots, which are: flow rate vs. pressure gradient and first and second derivatives of normalized permeability vs. Re. The analysis confirmed the Mei and Auriault (1993) and Forchheimer models during the weak and strong inertia regimes, respectively. Also, the Forchheimer dimensionless coefficient demonstrated an increasing trend when plotted against the Relative roughness, which was defined as the mean over the standard deviation of aperture. A universal correlation for the dimensionless Forchheimer coefficient could not be established from the plot. Therefore, we proposed investigating other geometrical parameters, which include contact areas, anisotropy, surface roughness, and aperture waviness to improve the correlation. Deriving a robust description of the Forchheimer dimensionless coefficient in terms of fracture relative roughness, will improve practices, such as well testing interpretation, history matching, and production forecasting of oil and gas.
Effect of N2 on CO2-Foam Assisted Enhanced Oil Recovery in Sandstone Reservoir
Authors: Hassan Mohamed , Gajbhiye Rahul 
Published: October 2018

Abstract
The global need for CO2 sequestration and associated advantages made CO2 gas injection as one of the important enhanced oil recovery (EOR) technique. The higher solubility of CO2 in oil, less injection pressure and miscibility makes it a favorable choice for EOR processes, but it suffers from high mobility and gravity override results in lower ultimate recovery. The high mobility and gravity override can be minimized by generating the CO2 foam with the aid of a surfactant. However, CO2 is unable to generate the foam/stable foam above its supercritical point (1100 psi, 31°C). These difficulties with 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.
To investigate the performance of CO2/N2 foam, core-flooding experiments were conducted at elevated pressure and temperature condition (higher than supercritical CO2 &#8211; 50°C and 1500 psi) in sandstone cores. Fluorosurfactant (FS-51) was used as a foaming agent and n-decane was used as model oil in all the experiments. The selection of foam quality and N2 fraction was optimized based on foam generation and stability tests. Every gas or foam flooding was preceded by seawater injection to simulate the behavior in the reservoir.
The results from the core-flood experiments showed that the CO2 and CO2/N2 foam flooding recovered an additional 34-40% of Original Initial Oil in Place (OIIP) indicating that foam flooding succeeded in producing more oil than pure CO2 gas injection processes. Additionally, the performance CO2/N2 foam injection was better than CO2 foam injection for delaying the breakthrough.
Overcoming Challenges in a Multi-Rig Turnkey Development Drilling Project Resulting in Top Level Performance
Authors: Al Fakih Abdulqawi , Ahmad Bilal , Javaid Muhammad O. , Yakhlef Redha , Stoyanov Emil K. , Crighton Alan , Ouahrani Louanas 
Published: October 2018

Abstract
There are several challenges when establishing a multi-rig operation in a new drilling or workover project. People from different companies and diverse backgrounds will have to work together and integrate with each other in a new working environment. These challenges are compounded when the drilling contractor is new to the country, rigs are newly built and ‘linguistic differences’ impacting efficient communication that exist between the staff of the drilling contractor and the project team.
This paper reviews the start-up and the learning curve for a project of four rigs to drill horizontal and vertical wells under LumpSum TurnKey (LSTK) contract. It presents the measures implemented to create a cohesive team and to accelerate learning. Also, it focuses on rig management, safety assurance and performance driving and monitoring.
The main challenges are highlighted, and the step by step solutions taken are described. The results discussed are showing the progressive improvement from a quality and safety standpoint. Drilling data from over 100 wells is analyzed to illustrate how workflows and innovative technologies contributed to progressively improve well delivery and surpass the established benchmarks. Finally, the paper discusses the merits of integration between the client, service companies and the drilling contractor, presenting a clear case where the whole is greater than the sum of its parts.
Review of Iron Sulfide Scale: The Facts & Developments and Relation to Oil and Gas Production
Authors: Okocha Cyril , Kaiser Anton , Wylde Jonathan , Petrozziello Lena , Haeussler Matthias , Kayser Christoph , Chen Tao , Qiwei Wang , Chang Frank , Klapper Markus 
Published: October 2018

Abstract
Oilfield iron sulfide (FeS) control and prevention have been mostly proprietary with several disparate solutions. Frequently FeS control involves milling, jetting, acid soaking, pulling and replacing tubing and manually cleaning tanks, vessels, separators and pumps. These methods are costly, wasteful and strenuous. This paper reviews the latest developments in oilfield FeS researches with an attempt to integrate viable solutions and expose unworkable practices.
In this work, we review and evaluate the most common FeS prevention and control solutions in an attempt to summarize the state-of-art FeS mitigation technologies. We have a closer look on FeS formation and control as well as potential integrated solutions. The paper reviews and differentiates treatment solutions between corrosion byproduct and FeS scale deposition from formation.
Most FeS scales have generally been treated as the same, using various treatment methods. Complex FeS polymorphs have resulted in different outcomes. This work focuses on different treatment options that assert to work for all FeS scale not differentiating between corrosion-byproduct and reservoir formed scale.
Successful case histories and suspected FeS polymorph are presented in this paper next to discussion of the model used to predict severity of the deposition and analyze the treatment design. FeS formation and deposition is evaluated, especially crystallography and fundamental studies into mechanistic aspects of FeS precipitation and how it relates to oilfield FeS precipitation.
In this paper state-of-art FeS scale research is summarized and differences to normal scale types are presented. Mineral scale in the true sense of going through the stages of nucleation, pre-crystallization, crystal growth, agglomeration and deposition. This is an important step change in consolidating all the disparate areas of FeS studies into an advanced solution focused approach. If FeS scale is considered a mineral scale then solutions such as scale inhibitor applications (continuous injection and squeeze) that work for common mineral scales should work for FeS deposition as well. Thereby moving FeS research from a relatively empirical level with vastly different approaches that are mostly unrealistic into solutions that will be viable in the oilfield.
First Use Worldwide of a Conventional Stage Tool Integrated With an Inflatable Packer Element for Casing While Drilling
Authors: Al Fakih Abdulqawi , Cengiz Husnu Ozgur , Aldape Alberto Gomez , Halma Jeremy , Alatiyyah Ahmed Subhi 
Published: October 2018

Abstract
The sustained impact of low oil prices continues to keep pressure on drilling economics whereby well construction teams must combine techniques to decrease Non Productive Time (NPT) therefore reducing cost, and improve drilling performance.
A casing while drilling approach was proposed in the top sections where borehole instability typically occurs after having a total loss circulation which increases the risk of mechanical stuck pipe. The presence of a water aquifer in the same section imposes the need for a cement stage tool and an isolation packer. A 9-5/8in trial job was planned and executed where drilling forces simulations were performed for the 9- 5/8in casing with buttress connections and conventional cement stage tools, packer elements and centralization to identify the maximum forces that could be experienced during the execution. A hazard analysis and risk control with a full contingency plan was performed. Three jobs were carried out after first trial with 13-3/8in casing buttress connections and conventional stage tool with successful results.
This paper describes the methodology and the successful execution of incorporating a conventional cement stage tool and packer element for casing while drilling applications to reduce both NPT and drilling risks as well as maintaining well construction integrity.
A Newly Developed Process for Wellbore Geometry Analysis from a Geomechanical Perspective
Authors: AlBahrani Hussain , Al-Qahtani Adel , Marhoon Zahrah , Hamid Osman 
Published: October 2018

Abstract
The wellbore quality can be affected by a multitude of factors that include drilling operations practices, drilling fluids quality, and geomechanical quality. Low quality wellbores lead to many complications that will result in well completion delay of. One factor of success in drilling operations is minimizing enlargements and tight spots. A new assessment process was developed to understand and analyze the influence of drilling operational practices on the wellbore shape. The analysis helps to identify the root causes of wellbore enlargement and propose mitigation solutions.
More than 20 wellbores have been analyzed. Those wellbores penetrate a carbonate sequence followed by a sandstone sequence. This is to characterize the variations in the wellbore shape, in terms of enlargements and tight spots, against a set of well-defined parameters affecting it. For these wellbores, the mechanical properties and the stresses were estimated to correlate the geomechanical aspects of penetrated formations to the behavior of the wellbore geometry. Cyclic lateral loading of the drillstring, mud-controlled swabbing, and unintentional deviation in some wellbores were also investigated.
The assessment concluded that cyclic lateral loading, due to reaming and vibrations, is a key factor of influence in changing the wellbore shape. Also, the mud-controlled swabbing proved to have a significant role in hole enlargements specifically. This was found to be evident in wellbores that employ highly viscous mud with a 30 min. gel strength of more than 25 lb/ft2. It was also found that using mud with low chloride concentration, below 30 g/L, contributed to the varying geometry of wellbores.
Applying the recommendations generated by this work will help to refine the quality of future drilled wellbores and consequently, mitigate the risks of pack-offs, stuck-pipe incidents, sidetracking, low quality logs, and casing-casing annular pressure. Also, this work will present a new approach for real- time wellbore quality prediction and monitoring using advanced data analytics tools.
Evaluating Wellbore Tortuosity in Horizontal Wells Caused by RSS Steering Mechanism
Authors: Oliveira Victor , Zahrani Bader , Alrushud Albaraa , Mohammad Muntasar 
Published: October 2018

Abstract
This paper describes a new approach to evaluating the effectiveness of the rotary steerable system (RSS) steering mechanism on wellbore tortuosity in horizontal wells. Wellbore tortuosity in drilling applications is defined as any unwanted deviation from the planned well trajectory. As reservoir objectives become more complex and exact, operators increasingly perceive the wellbore tortuosity as a serious concern in the process of drilling, completing, and producing wells.
Strict criteria were set during the classification process; the studied wells have a common geology and trajectory, and they use a very similar bottomhole assembly (BHA) design. The inclination values from the wireline tool are used to illustrate the attainable benefits in terms of wellbore quality and measure wellbore tortuosity. In addition, the wireline inclination data are compared with the actual measurement- while-drilling (MWD) survey to highlight the existence of the micro-dogleg severity (DLS) that cannot be measured by standard surveys.
Due to the theoretical differences in the steering mechanism between the various types of RSS, it has been claimed that utilizing one steering mechanism over another can produce a less-tortuous wellbore. These steering mechanisms have previously been classified as either push-the-bit or point-the-bit mechanisms. The relative merits of a push-the-bit steering mechanism vs. a point-the-bit steering mechanism is an over- simplification; neither mechanism can deliver the premium wellbore quality the industry demands from RSS. The present study introduces the continuous proportional steering method (CPSM), and demonstrates how this mechanism can provide superior wellbore quality by reducing wellbore tortuosity. In addition, a superior inclination hold performance is observed in horizontal sections drilled with the CPSM. Curve intervals are more continuous and smoothly drilled through the planned directional changes.
The research becomes a useful reference to analyze the performance and efficiency of RSS steering mechanisms across drilling and workover operations. Directional drilling service companies are encouraged and challenged to improve the efficiency and accuracy of RSS mechanisms, improving the hole quality and reducing micro-doglegs.