bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Slim-Matrix PDC Construction Boosts Drilling Efficiency: A Field Study
Authors: El Oufy Mamdouh , Ragheb Ahmed , Sherif Mohamed , Hanafy Omar , El Sherif Omar , Aguib Karim 
Published: July 2016

Abstract
One of the perceived drawbacks of matrix polycrystalline diamond compact (PDC) bits compared with steel PDC bits is their restricted open-face volume and smaller blade standoff, which is primarily caused by the matrix PDC bits' brittle nature. Increased blade standoff gives steel PDC bits a more hydraulically efficient body type, which directly affects ROP. In many drilling applications, operators switch to steel PDC to take advantage of their hydraulic efficiency, and recent developments in hardfacing material has expanded the range of applications of such bits. However, there are applications that are still dominated by matrix PDC bits, and a need arose for matrix material that can allow the molding of slim, hydraulically efficient matrix bodies.
A new matrix material with enhanced toughness allows for the design of a slim-body matrix construction. This innovative concept has been validated for structural integrity, which was the main perceived risk. The technology was rolled out for 8½-in and 12¼-in hole sections and deployed in a field test campaign in all of Egypt's different rock columns.
The effect and value of faster ROP increases with application complexity and depth and is directly proportional to rig spread rate. Hence, realizing the application limits of slim-body matrix technology was the main intent of this study. Success was measured by observing the effect of hydraulic efficiency across different fields in terms of ROP and cost savings. Further, to isolate the effect of slim-body construction, several tests were conducted between standard matrix and slim-body matrix construction using the same cutting structure layout and PDC cutter grade.
The slim-body matrix construction demonstrates significant improvement in cost per foot for applications and is directly proportional to UCS. This feature is advantageous in interbedded applications, where formations fluctuate from hard to soft and vice versa along the drilled column. This new feature has since been standardized in matrix bits and is being rolled out across various applications with the intent of tackling more expensive drilling operations to show a greater reduction in cost per foot.
Crosslinked Polymeric Gels as Loss Circulation Materials: An Experimental Study
Authors: Hashmat M. D. , Sultan Abdullah S. , Rahman Saifur , Hussain S. M. 
Published: July 2016

Abstract
In an oil/gas well drilling operation, loss circulation of the drilling fluid in a thief zone is a major problem without a unique solution. This problem is mitigated by using Loss Circulation Materials (LCM). One method to counter this problem could be the use of gel forming polymer systems; that would gel and seal the undesired zones and prevent losses.
In this work interaction of a commercial grade hydrolyzed polyacrylamide (HPAM) and a HPAM derivative with polyethleneimine (PEI) was studied, for the possible use of these polymeric systems as a loss preventive and sealing agent. These studies involved the identification of the optimum polymer/crosslinker concentration followed by their thermal stability testing. Dynamic rheology tests were conducted on the systems in order to examine their pre and post-gelation behavior. Differential Scanning Calorimetry (DSC) was used to study the gelation kinetics of the systems. Selected systems were then tested on a see through flow system to observe their performance in a porous media.
It was observed that attaining an optimum polymer/crosslinker identification is an essential first step towards attaining a rigid and stable gel. At optimum concentrations stable gels were obtained. Gel strengths were greatly enhanced by increasing temperature and aging time. This was reflected in both the rheology and the DSC tests. The DSC experiments provided great insight into the gelation mechanics of the polymeric LCM systems. For the best two systems, 100% solution to gel conversion was attained in nearly three and a half hours of total ageing time at 100°C isothermal condition. The same gelants when tested on the see-through flow setup were able to successfully prevent mud loss in a zone having 36% porosity and 300 D permeability at room temperature and moderately high pressure conditions.
This paper will build on and substantiate the idea of utilizing cross-linked polymer gels as LCM. It will introduce the findings of a self-fabricated see through experimental setup that related the cross-linked polymeric LCM's behavior with differential pressure, in a porous media.
Streamline Information Guided by Fuzzy Logic to Optimize Field Injection/Production Strategies
Authors: Y. BuKhamseen Nader , A. Al-Najem Abdullah , Saffar Ali , M. Al-Ghareeb Zeid 
Published: July 2016

Abstract
This paper presents an adaptive approach to optimize field injection strategies using streamline-based well allocations coupled with fuzzy logic. The strength of our approach comes from the fact that streamlines are generated by running full-physics in-house reservoir simulator. Streamlines provide great insights about well pattern connectivity and well allocation factors allowing the injection efficiency (IE) for each pattern to be determined. This enables us to assess and improve the performance of injectors highlighting patterns with low IEs, high voidage replacement ratio (VRR), and high water production to name a few.
Once streamline-based IEs are evaluated, a fuzzy logic system is developed and run to rank the injectors according to their injection performance. Three parameters: IE, water cut, and amount of injected water lost to the aquifer constitute the input to the fuzzy logic system. The fuzzy system categorizes the pattern IEs into four classes: poor, acceptable, good, and excellent. Similarly, it classifies the pattern water cut and the loss of injection into three categories: low, medium, and high. The fuzzy system then outputs an injection-ranking index (IRI) for each injection pattern to recommend a new injection strategy. The new injection rates are then fed into our in-house simulator and results are evaluated to quantify improvements in reservoir sweep efficiency.
This approach has been tested on large-scale simulation models with hundreds of wells and tens of millions of grid blocks. Results show noticeable improvements in injection efficiency for most wells resulting in reducing injection requirements, ensuring better sweep and pressure support without compromising oil production.
Multifidelity Modeling and Analysis of Matrix Acidizing Under Radial Flow Conditions
Authors: Ghommem Mehdi , Brady Dominic 
Published: July 2016

Abstract
Simulating the complex physics and dynamics associated with carbonate acidizing and wormholing phenomenon has been attempted with various types of modeling techniques. In this paper, we follow two modeling approaches with different fidelity levels to simulate carbonate acidizing under radial flow conditions, and describe the wormholing process. The first approach is based on a two-scale continuum technique extended to a three-dimensional cylindrical grid. This model requires discretizing and numerically solving a set of coupled partial differential equations governing the reactive transport of acid at darcy scale and the pore scale dynamics through the structure-property relations. The model shows good capability to reproduce qualitatively the change in the wormhole morphology when varying the acid flow rate. The model is also used to discern the impact of the rock heterogeneity on the wormhole initiation and propagation. While this high-fidelity approach is powerful in terms of capturing the main physical features of the wormholing dynamics at the core scale, the extensive computational resources and time associated with the use of this model could limit the capability of assessing different configurations and operating conditions for design and optimization purposes and upscaling to the field level. This shortcoming presents the need for the development of simplified models that embody relevant physical aspects and provide fast and reliable assessment of the acidizing performance. As such, we consider a second approach with reduced complexity based on combining two quantitative models of linear and radial acid flows in carbonate rocks to track the wormhole penetration and predict the pressure drop resulting from the acidizing of radial cores. A comparative study with experimental results shows that the model predicts well the pressure response and pore volume to breakthrough.
The Impact of the Geochemical Coupling on the Fate of Fracturing Fluid, Reservoir Characteristics and Early Well Performance in Shale Reservoirs.
Authors: Mehana Mohamed , Fahes Mashhad 
Published: July 2016

Abstract
The fate of the fracturing fluid in shale reservoirs is still a controversial issue. Despite the low recovery observed in field reports, neither the fate nor the impact of these trapped fluids is well-understood. The combination of the large surface area, mild reactive nature of shale and the massive trapped volume of fracturing fluids raises a question on the impact that geochemical interactions have on load recovery, well performance and reservoir characteristics, which is the focus of this study.
A fit-for-purpose model is built where a hydraulic fracture stage is modelled using LG-LR-DK model. The initial conditions are simulated by injecting the fracturing fluid, then shutting-in the well to allow the fluids to be soaked into the formation. Different relative permeability sets are used for high and low salinity water since the fluid's mobility is affected by its salinity. Actual connate water composition from Haynesville shale is used to study the impact of connate composition on geochemical coupling. The formation mineralogy and fracturing fluid composition impact on gas and load recovery is investigated.
The introduction of the oxygenated, low salinity, fracturing fluid to a reducing environment would definitely catalyze both precipitation and dissolution reactions depending on the formation mineralogy. The dissolution and precipitation rates show a positive correlation with the carbonate content of the rock. Interestingly, the incorporation of the dependence of relative permeability on ion exchange and fluid salinity might reveal the fate of the fracturing fluid. Overestimation of both gas and load recovery is observed when geochemical coupling is neglected. In addition, sea water shows an enhanced performance suggesting a good alternative fracturing fluid. Surprisingly, better performance is observed for less saline connate water cases. The carbonates reactions outweigh the clays reactions in most cases. Also, treating carbonates as only calcite results in more reactions compared to the dolomite case. Sensitivity analysis suggests that the concentration of SO4, K and Na ions in the fracturing fluid, and illite and calcite mineral content of the rock, along with the reservoir temperature are the main key factors affecting well performance. It is worth noting that the salinity contrast between the injected fluid and the formation brine shows a negative correlation with well performance.
In conclusion, the incorporation of the geochemical coupling in simulating fracturing fluid dynamics, and their impact on the load recovery and well performance, is essential. Therefore, careful selection of a fracturing fluid suitable for formation mineralogy will enhance well performance.
Development Strategy Optimization of Gas Injection Huff and Puff for Fractured-Caved Carbonate Reservoirs
Authors: Li Yong , Wang Daigang , Liu Zhiliang , Ma Xiaoping 
Published: July 2016

Abstract
Naturally fractured-caved Ordovician carbonate reservoirs in China have some distinctive characteristics: deep buried depth, developed multi-scale fractures, vugs and caves, no movable oil in pores, poor reservoir connectivity, isolated reservoirs with small developed volume and high production decline rate. How to effectively develop this kind of reservoirs is a major challenge. This paper presents the detailed development strategies of gas injection huff and puff for different representative fracture-cave type patterns after primary depletion and waterflooding.
Based on the geological study, representative reservoir patterns of fractured-caved carbonate reservoirs can be determined. And combined seismic interpretation, geological study and dynamic characterization, different development patterns can be identified and characterized. After that, simulation models of different development patterns with different fracture-cave architectures are built, and development strategy for representative isolated development patterns with gas injection huff-and-puff are detailed studied and optimized.
The technology is applied to K fractured-caved Ordovician carbonate reservoir of Tarim Basin in China. The mid-depth of K reservoir is 6500m with well annual production decline rate higher than 25%, and current oil recovery is only around 7% of OOIP. Through the geological and dynamic characterization, 3 representative reservoir type patterns are identified and characterized. And simulation models of the 3 patterns with different fracture-cave architectures for the three patterns are built to investigate the optimized development strategies of gas injection huff-and-puff. The optimized parameters include gas injection rate, cyclic soak time, cyclic injection volume, liquid off-take rate, etc., which are applied to the gas injection pilots in K reservoir, and the results show gas injection huff-and-puff can highly improve oil recovery.
This paper offers a case study on optimizing the development strategy of different reservoir patterns for fractured-caved carbonate reservoirs. It also provides a methodology and an improved oil recovery reference case for engineers and geologists to develop other similar reservoirs.
Enhancing Oil Recovery - Advanced Simulations for More Accurate Frac-Stages Placement
Authors: Saad Bilal , Negara Ardiansyah , Hussain Maaruf , Elgassier Mokhtar , Sun Shuyu , Abdullah King 
Published: July 2016

Abstract
Hydraulic fracture stimulation designs are typically made of multiple stages placed along the lateral section of the well using various well completion technologies. Understanding how multiple hydraulic fractures propagate and interact with each other is essential for an effective stimulation design. The number and placement of stages are important factors for optimizing the performance of the laterals. This in turn depends on accuracy in determining fracture interference. We present advanced simulations for accurate placement of well stages. In this paper, we use a 3-D fully coupled geomechanical-fluid flow simulator which incorporates anisotropic geomechanical properties. Densely complex natural fractures and lamination are built into the model based on available core and log information. Multiple fractures are concurrently imployed to simulate real life scenarios. Fluid pressures are incrementally computed such that stress state changes dynamically with time as it happens in real field situation. Our simulations were run on Cray XC 40 HPC system. The results demonstrate that the stress shadow effects can significantly alter hydraulic fracture propagation behavior, which eventually affects the final fracture geometry. The results show that there are large differences in aperture throughout the stimulation which persists to the end of pumping. Furthermore comparison between cases with and without complex natural fractures (discrete fracture network (DFN)) and lamination was conducted with even and uneven spacing configurations. Fracture interference and spacing analysis conducted based on model with perforation frictions shows that while spacing between fractures is important, the largest impact was observed in the presence of lamination and DFN. The large differences in the way the fracture propagates highly depend on the DFN connectivity. Late-stage connection throughout the model implies later disconnection when the pressure drops. Though the computations are time intensive, we believe this is a valuable tool to use in the planning stages for asset development to increase production potential.
The Use of Local Sand for Hydraulic Fracturing in Saudi Arabian Gas Fields
Authors: Alabbad Emad A. , Tarihoran Anton R. , Saldeev Ruslan , Al-Harbi Moataz M. , Al-Kulaib Hamad F. , Al-Atwi Mohammed A. , Hansen Jon E. 
Published: July 2016

Abstract
Hydraulic fracturing has been an essential part of the gas development program in Saudi Arabia. In particular, proppant fracturing treatments have increasingly grown in number in recent years, which provided an incentive to look for viable alternatives to imported proppants. A new hydraulic fracturing design that utilized local sand as nonstandard proppants was recently applied in gas wells producing from sandstone formations in Saudi Arabia. This paper presents the theory behind the new fracturing design and summarizes the main results and recommendations.
Sand quality-control lab tests were required prior to using Saudi Arabian sand as a propping agent in fracturing gas wells. The sand samples were analyzed for particle sizes, bulk densities, and compressive strengths. Well selection to apply the fracturing stimulation was then made based on a geomechanical criterion for the reservoir rock and the well's production performance. The treatment design utilized a channel-fracturing technique where the solids used comprised of roughly 65% natural sand and 35% ceramic proppants.
The results show successful placement of the fracturing treatment into the formation. Despite sand crushing, the data show reasonable stimulation results and productivity enhancements. A number of important findings were also realized based on the analysis of the production performance, the reservoir transient pressure data, and the recovered solids and liquids.
The discussions shared in this work including analysis of field data yielded important findings and recommendations. Particularly, the concept of applying nonstandard proppants, such as silica sand for hydraulic fracturing treatments is proven feasible. Overall, the new fracturing technique shows considerable potentials for sufficient process optimization and utilization of abundant resources in production operations.
Optimizing Reservoir Performance through Utilization of Autonomous Inflow Control Valve – Lessons Learnt from the World’s First Installation
Authors: Nugraha Ikhsan , AlBassam Terki K , Gallelli Alessandro , Mathiesen Vidar 
Published: July 2016

Abstract
One of the major challenges in mature oil fields is to improve recovery from existing fields by developing and implementing new technologies that make operations efficient and cost effective. For a reservoir with a water or gas drive mechanism, the mobility ratio between oil and water or gas becomes more critical due to the lower viscosity of water or gas. Observably, breakthroughs can occur within relatively short periods of production time. Once breakthrough occurs, gas or water production can rapidly dominate production prompting well intervention or the shutting-in of production, leaving unrecovered oil behind.
Inflow control device (ICD) and autonomous inflow control device (AICD) have shown oil production and recovery can be increased significantly with better inflow control/pressure regulation along the lateral, which to some degree has resulted in breakthrough delays. However, neither ICD nor AICD are able to shut off unwanted gas and water production completely. The autonomous inflow control valve (ICV) offers the functionality of conventional ICD and can actively shut off unwanted fluid completely.
The paper describes the development of Autonomous ICV, experimental test results, and preparations prior to the completion installation. The main challenges and conclusion from the field tests are presented and discussed based on the initial flowback data where the functionality of Autonomous ICV was verified, i.e., by shut-off of low viscosity fluid, such as water, and opening for oil with higher viscosity.
First Time Live Descaling Operation in Saudi using Coiled Tubing Fiber Optic Real-Time Telemetry Rugged Tool, Foamed Fluid and Pressure Fluid Management System
Authors: Espinosa G Mauricio A. , Leal Jairo A. , Driweesh Saad M. , Buali Mustafa F. , Khnaifir Waleed K. , Jasim Ali J. , Noaman Yousef M. , Sa Rodrigo , Arifin Mohammad 
Published: July 2016

Abstract
Saudi Aramco has long faced significant challenges to remove scales from the wells due to the high H2S contents and the sub hydrostatics reservoir pressure. Conventional techniques often fell short of expectations in the past, there had been cases of uncontrolled H2S releases at surface, which caused major HSE issues to the personnel; also coiled tubing (CT) got stuck due to sudden loss of circulation stemming from the inability to control the bottom-hole pressure and the instability of the fluid system during the scale removal treatment. As a result of those repeated issues, scale removal treatments were suspended for some time waiting for a safe technique to be devised. As a first step, the service company proposed to use a non-damaging chemical plug technique to temporarily plug the open perforations during the scale removal treatment, in an effort to avoid H2S release and to maintain circulation. The first results of this technique showed a marked improvement, which led the operator to resume the descaling operations, but in some operations the isolation process was extended several days and a large amount of fluid were injected into the formation, leading to induced damage, requiring high volume acid stimulation treatment and longtime flow back operation, to get the well back in production.
To further optimize descaling operations via CT in Saudi Aramco, a novel scale removal technique was introduced that leverages the real-time downhole monitoring capabilities of CT equipped with fiber optics, to obtain a constant feedback on downhole conditions and allow swift adjustments to ensure safe operations. It also uses a redesigned foam system and implements a new pressure and fluid management system (PFMS), to eliminate the use of the temporary plug across the formation.
With CT fiber-optic real-time telemetry, engineers can control the bottom-hole pressure throughout the intervention, to maintain the well slightly over-balanced and to prevent H2S from being released during fluid circulation. This system counts with a bottom-hole assembly (BHA) that gathers a full array of real-time sensors (pressure, temperature, casing collar locator, gamma ray, load measurements), and is compatible with downhole tools that require high flow rate to operate — in this case, a 2-7/8-in. turbine with a nominal flow rate of 2.8 bpm). This BHA can withstand a high level of shocks, vibrations and bottom-hole temperatures in excess of 300°F. As for the foam system, it ensures stable solid transport from downhole to surface conditions minimizing leak off into the formation, while the pressure flow management system (PFMS) is used to accurately control wellhead pressures, thanks to an array of auto chokes to control solid returns, and to remove entrained gasses (including H2S) from the returning fluid.