bluuebunny/crossref_metadata_2025_split huggingface dataset:
Microstructural and Rock Mechanical Study on Selected Core Plugs Samples from Unconventional Formation
Authors: Al-Badairy Hameed , Alqam Mohammad , Al-Nakhli Ayman 
Published: June 2017

Abstract
Tight gas is the general term applied to low permeability, low deliverability, and low porosity gas-producing formations. Future potential for gas production lies among others in tight gas reservoirs. Gas wells in these reservoirs are economically marginal and they cannot be developed using conventional technologies. These reservoirs must be hydraulically fractured to produce because of the natural ineffective reservoir drainage, which is due to extremely low permeability.
In this paper, an integrated approach was applied to investigate the role of rock mechanical properties. Also, samples were selected for microstructural and mineralogical characterizations using advanced microscopy and spectroscopy analytical techniques. Additionally, ultrasonic compressional and shear velocities were measured on each sample and dynamic Young's modulus and Poisson's ratio were obtained. The acquired topographical images showed the presence of nanoscale pores and micro-cracks in most of the examined core samples. The energy dispersive X-ray spectroscopy (EDS) general area analyses revealed that the examined formations were composed of oxygen, silicon, aluminum and magnesium as the major elements with appreciable amounts of potassium, calcium, iron and carbon. EDS spot mode analyses revealed the presence of white particles that were found to be iron-rich compounds. The outcome of this study is to develop practical empirical correlations to assist in predicting rock mechanical properties. The ultimate objective is to establish formation dependent correlations that relate mechanical properties, such as rock strength, to a log measured physical property such as sonic velocity. The mechanical properties are critical input for many field problems, such as wellbore stability, sand production control, fracturing, casing design and perforation. The final outcome of this project will result in tremendous reduction of testing time and cost.
Integrating Field Performance and History Matching Uncertainties Using Fuzzy Logic to Minimize Well-Placement Risks
Authors: Khan Waqas A. , Sudirman Sharizan B. , Qahtani Ghazi D 
Published: June 2017

Abstract
To a great degree, the success or failure of a field development plan depends on the choice of well locations, which together with areal and vertical sweep drives hydrocarbon recovery from the field. Choosing the optimum well locations is, however, non-trivial and requires a thorough understanding of hydrocarbon reservoir performance and properties. Even after the locations are identified there is a need to further rank the wells in terms of confidence as part of the risk assessment. Many methods currently used to place wells rely heavily on the final history matched model, which may be misleading because history matching is a non-unique solution and different history matched models may give different prediction results.
This paper presents a workflow using the fuzzy logic approach that combines history matching uncertainties with field performance data to help generate a confidence index for well placement. In contrast to neural networks, which take training data and generate opaque models, fuzzy logic allows a geoscientist to build models on top of experience from the experts. All the expert opinions and reservoir understanding can be dictated as a simple set of rules and logic to define the well placement confidence index, which could then be used to propose field development plans with a much higher level of confidence. This, in turn, helps with better decision making and reduces the risk involved in drilling additional infill wells.
Common Misinterpretations of Gas Condensate Reservoirs
Authors: Abdallah Muhammad S. , Al-Zawad Makki A. , Fraim Michael L. 
Published: June 2017

Abstract
Geopressured gas reservoirs materialize as a result of a variety of factors, some of which include the rapid compaction of sand/shale sequences and the uplift of sediment layers by a salt intrusion. These gas reservoirs are commonly characterized by a significant drop in formation compressibility owing to the collapse of the rock matrix, and are notorious in the drilling and production industries for the various problems they cause. This paper reviews the retrograde gas condensate production data presented in SPE-2938 (Duggan, 1972) with modern analysis tools to show that gas condensate banking can cause classic material balance analysis to mimic the shape of a geopressured gas reservoir.
The condensation of liquid hydrocarbons below the dew-point in a gas reservoir, and the onset of water influx from a leaky fault can complicate the material balance analysis of these reservoirs and may lead to engineers mistakenly classifying them for what they are not. Failure to properly classify a gas reservoir may lead to an incorrect estimation of original gas in place (OGIP). Accurate determination of initial gas in place is of utmost importance in the process of estimating gas reserves. A lower estimation of OGIP or not accounting for condensate banking in low permeability zones may lead to early abandonment of a gas well or significant loss of reserves for an operating company.
Results show that proper consideration of the two-phase Z-factor in the material balance calculations calculated via the constant volume depletion test (CVD) leads to a more accurate determination of gas reserves, in addition, the change in formation compressibility is shown to be consolidated sandstone as opposed to geopressured rock matrix.
This paper aims to demonstrate a simplified procedure for the flow-after-flow well test of determining the effect of condensate dropout within the vicinity of the wellbore as the flowing bottom-hole pressure (BHP) drops below the dew-point pressure. Two-phase pseudo pressure was calculated from a constant composition expansion (CCE) using Whitson's Method (Whitson, 1983) for condensate banking and measured gas composition. The classical Anderson "L" gas reservoir of the Mobil-David field in South Texas (Duggan, 1972) was chosen as a case study.
Implementation of the proposed procedure will serve as an aid to gas reservoir engineers in properly classifying potential gas condensate reservoirs.
Innovative Approach to Optimize ESP Power Consumption through Developed Software
Authors: Almukhtar Mohammed A. , Alabdulmohsin Yousif A. , Shawly Alaa S. , Shehri Ayedh M. , Shammari Nayef S , Al-kuhlani Mohammed 
Published: June 2017

Abstract
Maintaining oil production while both water cut and reservoir pressure are changing with time is a challenging task especially for fields equipped with artificial lift systems such as Electrical Submersible Pump (ESP). ESPs have a defined recommended operating range (ROR) that can reduce the flexibility of the system therefore a variable speed drive (VSD) unit is being used to extend the ROR. A surface choke is also another option to adjust the flow rates and control the ESP to operate within its recommended range. However, inefficient use of both options can be detrimental on the life cycle of the production system.
High VSD Frequency will increase the motor speed which leads to increased power consumption. Low choke setting causes high hydraulic losses across the choke that can lead to wastes of energy. In oil fields equipped with ESPs, power consumption as well as ESP run life play a significant role in specifying the operation cost and economical life of the field. Therefore, it's essential to optimize the operation conditions of the ESP to optimize the operation conditions of the ESP through minimizing power consumption while maintaining a production rate that fall within the pumps ROR. Utilizing a technique that can quickly provide the best choke and frequency setting is a key to achieving more optimized operation in a dynamic field.
This paper will discuss an in-house developed application that can calculate the minimum ESP motor operating frequency and the optimum choke setting point required to maintain the production rate at the minimum power consumption and lower motor speed. With the availability of real-time data from the surface and down-hole equipment, the optimization process was automated by collecting data and modeling surface equipment and ESP. this application is being used to optimize an entire field and the pilot test showed very promising results. A substantial 2000 KVA, which is equivalent to 1600 KWh, was saved by adjusting only 57 wells.
Residual Saturation: An Experimental Study of Effect of Gravity and Capillarity during Vertical and Horizontal flow
Authors: Adebayo Abdulrauf R. , Barri Assad A. , Kamal Muhammad Shahzad 
Published: June 2017

AbstractMinimum residual oil or gas saturation is desired in any oil and gas field operation while maximum residual gas saturation is desired in gas (CO2) sequestration projects. In the literature, many studies have reported various factors that affect residual saturations such as wettability, interfacial tension, viscosity ratio, and injection scheme. There have also been reports of the directional dependence of residual saturation due to anisotropy. The anisotropy is believed to be caused by variation in rock minerals and/or properties in different directions. However, the effect of the interplay between gravity and capillarity in a low velocity flow away from the injection wells during gas sequestration in saline aquifer has often been neglected in many studies. Gas flows vertically upward and against gravity at a very low rate after they have been injected into the underground aquifer. During this flow process, some key parameters that are often ignored in the laboratory estimation of the relative permeability curves that are used to model and forecast the multiphase behavior, are present. They are gravity and capillary effects. In addition, vertical upward flow core flooding experiments are rarely performed when generating relative permeability curves in the lab for CO2 sequestration modeling. In this study, the influence of the interplay between gravity and capillary forces on residual saturation during flow in horizontal and vertical direction was investigated and compared. Series of core flooding experiments at reservoir flow conditions was performed in both horizontal and vertical flow direction on different rock samples of varying mineralogy and permeability. Results obtained so far indicate directional dependence of residual saturation even for homogeneous and isotropic rocks. Residual fluid saturation is higher when flow is in vertical direction as compared to horizontal flow direction. It was concluded that directional dependence of end saturation is not due only to heterogeneity but also due to the flow direction itself as observed in homogeneous and isotropic rocks tested.
Calculation of Sulfur Deposition in Gas Condensate Wells in Middle East
Authors: Al-Jaberi Jaber , Al-Azani Khaled , Fraim Michael 
Published: June 2017

Abstract
Sulfur deposition has been one of the major concerns in the sour-gas industry. This is due to the significant reduction in the deliverability of a gas well. To illustrate, in deep sour gas reservoirs, elemental sulfur often exists as a trace element in vapor at reservoir pressure and temperature. Reduction in reservoir pressure and temperature due to production of gas to the surface reduces sulfur solubility in the gas phase so that the dissolved elemental sulfur precipitates in the wellbore region of the sour gas well, thus building up sulfur scale over a period.
The compositional simulation model was GEM from CMG and we used WinProp for phase behavior of a generalized deep sour gas well in the Middle East.
We observed that the deposition of sulfur is in the tubing and not like salt/scale deposition in the casing which is due to evaporation and super saturation in the brine phase as it produced through the perforations.
Optimizing Injector-Producer Spacing for CO2 Injection in Unconventional Reservoirs of North America
Authors: Alfarge Dheiaa , Wei Mingzhen , Bai Baojun , Almansour Abdullah 
Published: June 2017

Abstract
Shale oil reservoirs such as Bakken, Niobrara, and Eagle Ford have become the main target for oil and gas investors as conventional formations started to deplet and diminish in number. These reservoirs have a huge oil potential; however, the predicted primary oil recovery is still low as average of 7.5 %. Carbon dioxide (CO2) flooding has been a controversial approach to increase oil recovery in these poor-quality formations. This study investigated the effect of injector-producer spacing, in range of 925-1664 ft, on CO2 performance in these plays by using numerical simulation methods. CO2 utilization value under differrent injector-producer spaces has been calculated. Increments in oil production rate, cumulative oil, and oil recovery factor have been determined in 1, 5, 10 years of CO2-flooding start-point. In this study, unfractured horizontal injectors are modeled to avoid conformance problems in natural fractured unconventional formations. Furthermore, the physical behavior for CO2 flooding under different conditions has been discussed. Finally, simulation results were analyzed and compared with some of pilot tests which had been conducted in North Dakota and Southeast Saskatchewan.
The results indicated that CO2 flooding performance would be more pronounced, by increasing oil production rate and oil recovery factor, as the injector-producer spacing minimized. However, CO2 utilization value is significant high when the injector-producer spacing is very short due to depleted volume closeness. Interestingly, CO2 utilization value for all spacing scenarios would gradually be reduced with flooding time. This reduction in the injected-gas utilization-value has been matched with the pilot test which performed in southeast Saskatchewan. In addition, CO2 efficiency indicator is generally in range of 4.85-44.5 Mscf/STB in these unconventional reservoirs which is relatively high as compared with conventional reservoirs. These results have been confirmed by a good match which has been obtained between simulation results and some of pilots’ performance. This paper provides a thorough idea about how to optimize the injector-producer spacing for CO2 flooding in these complex plays. Also, this work explains that CO2 efficiency indicator is different in these unconventional formations as in conventional reservoirs.
Low-Carbon Steel Corrosion at High Temperatures by Ammopolycarboxylic Acids
Authors: Ng Jun Hong , Almubarak Tariq , Nasr-El-Din Hisham , Almubarak Sama 
Published: June 2017

Abstract
Aminopolycarboxylic acids (APCAs) have been used in a variety of applications ranging from textiles to pharmaceuticals. They are also commonly used in the oil and gas industry for scale removal, standalone stimulation, and iron control. Due to the commonplace usage of APCAs, it is important to understand the corrosion that can results from using APCAs, and the methods that can be applied to reduce corrosion damage resulting from their use. The objective of this work is to evaluate the corrosion rate of APCAs on low-carbon steel at high temperatures and to determine the mechanism of corrosion.
At high temperatures, conventional acids such as hydrochloric acid (HCl) are extremely corrosive, lack penetration, and have sludging tendencies. Several organic acids such as formic acid and citric acid were proposed to overcome these shortcomings. However, these organic acids have displayed problems with solubility and compatibility. Chelating agents show good dissolving power, low corrosion, low sludging tendencies, and excellent iron control and have been successfully used to replace HCl in certain applications. Furthermore, some of them are easily biodegradable and environmentally friendly.
The results obtained indicate that the corrosion rate of ethylenediaminetetraacetic acid (EDTA) was the highest at both temperatures with a rate of 1.07 lb/ft2 at 350°F and 0.858 lb/ft2 at 300°F. L-Glutamic diacetic acid (GLDA) had the lowest corrosion rates of 0.754 lb/ft2 at 350°F and 0.724 lb/ft2 at 300°F. Hydroxyethyl ethylenediamine triacetic acid (HEDTA) showed intermediate corrosion of 0.974 lb/ft2 at 350°F and 0.803 lb/ft2 at 300°F. Furthermore, the mechanism of APCA corrosion of low-carbon steel was found to be a combination of chelant enhanced dissolution and cathodic reduction of the APCA. Chelant enhanced dissolution involves dissolution of the oxide layer on the surface of the metal and is accelerated at high temperatures by reductive dissolution. Cathodic reduction of carboxylic acid groups of APCAs was determined to be responsible for the corrosion of the bare metal layer. The work provided will provide better understanding of low-carbon steel corrosion by APCAs at high temperatures and opportunities to pursue an effective corrosion inhibitor.
First Deployment of a New Integrated Expandable Under Reamer Technology With a Conventional Drilling BHA in a Vertical Well in KSA
Authors: Al Dabyah Ali A , Schimanski Michell , Grymalyuk Sergiy 
Published: June 2017

Abstract
This paper presents and discusses the results of a field application where a new integrated expandable under reamer technology was deployed in the Uthmaniyah field located in Saudi Arabia.
The wells in the Uthmaniyah field usually are vertical and high interface severity is encountered in hard Dolomite/Limestone intervals. Conventional directional drilling bottom hole assemblies (BHA) are deployed in these wells. This interface severity is likely to initiate axial and lateral vibrations causing bit and BHA damages.
The 12¼-in. bore hole section of a Utmaniyah well was planned to be opened up to 14-in. For the first time in this field a new intelligent under reamer technology was used for the under reaming application. The new on-command digital, expandable under reamer is fully integrated into the BHA and can be monitored and controlled from the surface. The real-time feedback from the reamer includes tool vibration and stick slip (VSS) data, and confirmation of blade activation status and position, reducing operational uncertainty during reaming and saving time for a shoulder test. The under reamer tool has unlimited activation cycles that provide the capability of selective reaming. The flexible placement of multiple reamers in the BHA enables near-bit and main reaming applications, and a combination of both. When used for near-bit reaming service, the reamer can reduce the rat-hole length to 4 m, compared to an application where it is placed 40 to 70 meters behind the bit. Significant time savings can be achieved by eliminating the dedicated rat-hole run.
In the mentioned application in the Uthmaniyah field the new reamer achieved a high rate of penetration and reliable hole enlargement across a long section containing Minjur formation in one run.
The BHA was designed as a pendulum assembly to keep the borehole vertical with the reamer positioned 63 ft behind the bit. A second run was planned to eliminate the remaining 63 ft rat hole by repositioning the reamer below the Measurement While Drilling (MWD) and Logging While Drilling (LWD) suite, resulting in a final rat-hole of approximately 12 ft.
The technology proved its effectiveness as a reliable main reamer as a part of conventional non-rotary steerable BHA in an interbedded hard formation with Dolomite/Limestone intervals. Drilling optimization services were utilized to illustrate and optimize weight distribution, minimize vibrations and match bit and reamer aggressiveness.
The paper will summarize and describe the results and features in detail, and demonstrate how they can help the operators to reduce operational risks and save cost.
Improve Plugging Efficiency in Fractured Sandstone Reservoirs by Mixing Different Preformed Particles Gel Size
Authors: Alhuraishawy Ali K. , Sun Xindi , Bai Baojun , Wei Mingzhen , Imqam Abdulmohsin , Almansour Abdullah , Abdulaziz King 
Published: June 2017

Abstract
The oil recovery from fractured reservoirs is usually low, which is usually caused by the existence of areal formation heterogeneity. Preformed particle gel PPG has been used successfully use to reduce Heterogeneity and improve sweep efficiency. Low salinity waterflooding (LSWF) was recognized by the oil industry to increase displacement efficiency. The main objective of this study is to test the effectiveness of coupling these two technologies to increase oil recovery. Additionally, this study will determine the optimum PPG size to use with LSW to improve conformance control in the fractured sandstone cores.
Semi-transparent five-spot model made of sandstone cores and acrylic plates were built to visualize the sweep efficiency from the coupled methods. Sandstone cores were saturated by 1.0% NaCl and then light oil was injected to simulate initial water saturation before the fracture was made. Brine at different salinities was injected initially into the fracture model to determine oil recovery. PPG with different sizes was injected later to reduce the fracture conductivity and increase sweep efficiency. Brine was injected again after gel treatment to determine the oil recovery improve after the gel injection.
Laboratory experiments showed that the oil recovery factor and the water residual resistance factor (Frrw) increased when the low-salinity water was used for injection. However, the PPG extruded pressure decreased when the PPG swelled in a low-salinity water. Additionally, mixing different PPG size resulted in higher plugging efficiency than uniform PPG size and Frrw decreased as increased flow rate. Combining two different preformed particle gel sizes can improve plugging efficiency and, in turn, improve sweep efficiency and enhance conformance control.
Running LWD Azimuthal Sonic and Azimuthal density in tandem confirms the Azimuthal sonic technology for Real time dip picking and geosteering application. Middle East case study
Authors: Nestyagin Andrey , Al Arfi Saif , Mostafa Hassan , Elkholy Mohamed , Fekry Mohamed , Awad Huda , Mohamed Omar 
Published: June 2017

Abstract
Proper Well Placement in multi layers thin carbonate reservoir could be challenging due to high geological uncertainty. Using radioactive sources to evaluate porosity & formation dipping is effective, but considering the drilling environment & high risk to get stuck makes a lot of restrictions on using of the nuclear tools. This paper is a case study illustrating utilizing absolutely sourceless azimuthal sonic in a comparison with conventional radioactive density as a highly effective alternative sourceless geosteering method & adds extra formation evaluation values.
The technique provides azimuthal sonic data were acquired with a focused unipole tool which recorded the measured waveforms and computed Compressional and Shear velocities in 16 azimuthal bins yet Quadrant Compressional and Shear slowness were computed by stacking all 16 bins of data in Realtime, which gave very high signal-to-noise ratios and excellent data quality. The azimuthal Quadrant real-time sonic porosities were effectively used to well placement in the target reservoir, later on the full 16 bin azimuthal memory were examined to understand the additional advantages of using the azimuthal sonic even before approaching the main bed boundaries.
Both of Azimuthal Density & Azimuthal Sourceless Sonic measurements were able to detect the boundaries of the target zone, allowing accurate stratigraphic interpretation as well as dip picking calculation to ensure proactive geosteering and maintain the well trajectory as per the plan. It was proven that the Sonic lengthy depth of detection can add an additional safety margin to enable adjusting the well trajectory in the reservoir at the optimal angle, the comparison chanced later against the Azimuthal density image was matching very well and emphasised the formation dipping.
This case study proves the capability of using LWD Azimuthal sonic as an effective & alternative sourceless porosity for geosteering and formation dipping calculation purposes.