bluuebunny/crossref_metadata_2025_split huggingface dataset:
Full-Range Quantitative Cement Bond Evaluation with LWD Sonic: The Right Way of Approach Using a Hybrid of Amplitude and Attenuation
Authors: Izuhara W. , Yamamoto H. , Blyth M. , Saenz E. 
Published: October 2017

Abstract
Cement evaluation plays an important role in determining well integrity, to ensure zonal isolation in a wellbore. Cement evaluation has recently evolved to include Logging-While-Drilling (LWD) sonic tools due to the multiple benefits of LWD logging compared with conventional methods, including tool conveyance, reduced tool eccentering effects, time lapse evaluation, etc. On the other hand, there is an LWD-specific challenge which is the contamination of the casing mode by the drill collar mode. The recent development of the algorithm to use the attenuation through receiver array of both the tool and casing arrivals, gave an initial insight into how to overcome the problem.
We investigated the applicability of a hybrid method using both the signal amplitude and attenuation which was introduced in 2014, and have now further enhanced the processing method. A new processing workflow has been developed to improve the measurement. In the new workflow, the waveform envelope is initially calculated by the Hilbert transform, and the signal amplitude is then evaluated in a time window, in which both casing and collar modes are present. Next, the apparent attenuation rate of the signal across the receiver array is considered. The applicability of the method is validated by an intensive numerical modeling study using finite difference methods (FDM) with detailed tool structures in various casing sizes, mud properties, and cement types. We also conducted a sensitivity study of the apparent signal attenuation to the bonding over the receiver array and the bonding over the transmitter-receiver (TR) spacing, respectively, to identify in which zone of bonding the hybrid method is more sensitive.
Field data examples of quantitative cement evaluation are presented for different LWD tool sizes and casing sizes together with wireline reference to demonstrate the validity of the new method and the suggested quality control processes. All of the results finally prove that the hybrid method using both amplitude and attenuation is the right way for full-range cement bond evaluation with LWD sonic tools.
Losses? No Problem. Unconventional Solutions to Cure Unconventional Losses and Improve Wellbore Instability Problems in Saudi Arabia
Authors: Heinold Thomas , Shine Joseph 
Published: October 2017

Abstract
Saudi Aramco faces a wide array of challenges maintaining wellbore stability during drilling and primary cementing operations. As a result, it has implemented revised strategies and methods to remediate losses during well construction operations. The origin of these strategies, swith some adopted from deepwater operations, has led to improved zonal isolation and operational efficiencies. The conventional methods used to cure losses during drilling with cement plugs can be inefficient usually requiring multiple attempts with mixed success. A revised method focuses on hydrostatics of the cementing fluids as well as advanced placement methods based upon the loss circulation boundary conditions to improve the plug success rate. During primary cementing across multiple zones with risks ranging from ultra-high permeability, low bottom hole pressures, and highly natural fractured carbonates, the risk of losses during cement placement has led to inconsistent zonal isolation. A revised strategy for the cementing fluids used during primary cementing based upon these same risks will demonstrate the improved zonal isolation success. The manuscript details the methods, strategies, and case histories discussed above.
High Pressure Gas-Lift: Is Industry Missing a Potentially Huge Application to Horizontal Wells?
Authors: Elmer D. , Elmer W. , Harms L. 
Published: October 2017

Abstract
Traditional gas-lift technology blossomed between 1929 and 1945, with about 25000 patents being issued during this time (Wikipedia 2017). Minimal innovation other than improved materials has been realized since then, with gas-lift in the 1000 psig injection pressure range being the norm onshore. The case for high pressure gas-lift to eliminate the need for problematic gas-lift valves is made, as technology and conditions exist to implement it now, as has been done offshore.
The concept of High Pressure Gas-lift (herein after referred to as HPGL), as discussed in SPE 14347 (Dickens 1988), has two potential onshore applications. First, total elimination of gas-lift valves in horizontal wells with sub-7000 psi BHP's. This is feasible due to improvements in compressor technology created to support CNG fuel, and elevated casing pressure ratings necessitated by hydraulic fracturing requirements. A second application is replacing failure-prone submersible lift as the initial form of artificial lift in horizontal oil wells by reversing flow with high rate, high pressure gas-lift.
The case for eliminating failure-prone gas-lift valves is self-evident. However, the case for the second application will be proffered. Conventional gas-lift, while recognized as excellent for producing high volumes of solids- laden fluid from deviated wells, underperforms ESP's in new horizontal oil wells due to frictional losses associated with high tubing flowrates. The case will be made that SPGL combined with reverse flow mitigates the frictional losses associated with high flowrates. Similar to a coil tubing cleanout using high pressure nitrogen, high pressure natural gas can lift large volumes of fluid without the need for gas-lift valves.
Technology and products for HPGL currently exist. Multiple compressor designs will be summarized to show that only one additional stage of compression is needed to support HPGL, with three and four stage designs being capable of performing the task. The recommendation will be made that HPGL compressors be assembled from readily available components, and that multiple pilot tests be made by industry. The importance of maintaining temperatures through the compression process high enough to prevent hydrocarbon condensation will also be explained.
A Conceptual Shale Gas Model Validated by Pressure and Rate Data From the Haynesville Shale
Authors: Marsden J. , Kostyleva I. , Fassihi M. R. , Gringarten A. C. 
Published: October 2017

Abstract
This paper presents a conceptual model of the Haynesville Shale which matches dynamic pressure behaviors over periods of 2 to 5 years of all 20 wells investigated. It assumes three stages of productivity deterioration, with matrix permeability declining first, followed by decreasing fracture conductivities and the onset of pseudo-skin effects which increase linearly with time.
The shale reservoir is simulated as a two-zone repetitive element, consisting of a fractured zone in contact with the wellbore and surrounded by a matrix zone representing the rock unaffected by fracturing. The two zones have different initial permeabilities and permeability-pressure relationships. The permeability-pressure function for the matrix is obtained from laboratory measurements and is the same for all wells. That for the fractured zone is determined by history matching and is well-specific.
The matrix permeability decreases as soon as its pore pressure begins to fall whereas the decline of the fractured zone permeability only starts below a threshold pressure, and at a time which corresponds to a distinctive behavior on a normalised rate versus cumulative production plot. As the bottomhole pressure decreases further, matching between simulated and observed data requires the introduction of a pseudo-skin factor increasing linearly with time, which could correspond to the effective fractured zone becoming smaller as the pressure declines.
Rheology, Regain Fracture Conductivity and Viscous Fingering Phenomenon for Proppant Suspension in CMC Hydraulic Fracturing Fluid
Authors: Aliu Abdulmumin Omeiza 
Published: October 2017

Abstract
In this current work, an unconventional fracture fluid was analysed for its rheological properties, ability to have relatively higher regain fracture conductivity after clean-up from proppant pack and ability to suspend and transport proppants to the fracture. The fracture fluid uses sodium carboxy methyl cellulose (Na-CMC) as thickener and zirconium based compound was adopted as crosslinker. This work attempts to expand on previous work done on CMC fracture fluids and results presented are completely experimental.
The crosslinked Na-CMC gel was found to have a better viscosity compared to the conventionally used guar gels made from the hydroxyl propyl guar (HPG) thickener. It was also found that CMC was able to withstand considerable viscosity at elevated temperature of about 90 degrees Celsius. Images from the Scanning electron microscope (SEM.) showed that CMC's microscopic structure with strong connected bonding was responsible for its enhanced viscosity. The fracture conductivity in pack with broken CMC fluid was found to have higher regain percentage when tested using API RR 61 cell procedure. The high residue produced in boken HPG fluid was found to be highly responsible for lower regained fracture conductivity in the proppant pack. SEM structural image analysis of the proppant versus CMC interaction may also be a responsible factor for its enhanced conductivity when compared to HPG. The alternate slug fracturing method was adapted to the CMC fluid using a fluid mobility ratio of 150-200 and success was achieved to a reasonable extent.
The overall result implies that CMC fracture fluid could be an effective substitute for guar based fracture fluid based on the improved rheology, better regain fracture conductivity and excellent proppant suspension ability of the CMC when compared the conventional guar based fluids.
Geochemical Modeling of the Interplay Between Potential Determining Ions During Brine-Dependent Recovery in Carbonate Rocks
Authors: Awolayo Adedapo 
Published: October 2017

Abstract
Brine-dependent oil recovery in carbonate rocks has developed into an active area of research in the past two decades. It is well documented in the literature that wettability of carbonate rocks is altered due to desorption of oil acid groups from rock surfaces by the adsorbed sulfate, while the divalent cations co-adsorbed to maintain the surface charge balance as well as to reverse the oil-surface charge. Though the symbiotic interaction between active ions (Ca2+, Mg2+, and SO42−) and the rock surface has been established but how they systematically interplay at different conditions have not been well explored and available data seems inconsistent. In the present work, we develop a reactive transport model that includes various reaction sets like aqueous reactions, mineral reactions in terms of precipitation and dissolution, and surface sorption reactions in terms of adsorption and ion exchange to investigate and discuss the affinity of these active ions toward the rock surface. The important thermodynamic properties were obtained by using the model to interpret single-phase experiments. The model results were in remarkable agreement with the produced ion histories reported from the single-phase experiments. There were delays observed in the produced active ion concentrations because of retention at the rock surface. For two-phase experiments, the model excellently replicated the produced ion histories and oil recoveries obtained during various brines injections, using the same thermodynamic parameters. Although, the ion transports are impacted by the presence of oil because of reduced surface area accessible to the active ions. The established thermodynamic parameter can be applied to predict various brine-dependent recovery processes in different carbonate lithology as no significant difference was observed for the interplay between active ions and either chalk or limestone rocks.
An Investigation on Qualitative Analysis of Hydraulic Fracture Simulation for Field Development Planning
Authors: Bhore Niranjan 
Published: October 2017

Abstract
Hydraulic fracture simulation in a variety of methods is being undertaken to better describe the stimulated reservoir in a commercial full field reservoir simulator. Studies so far suggest that the reliable evaluation of the stimulation performance is critical for field development planning. Therefore, pressure transient studies, near wellbore simulation techniques, variety of gridding techniques, LGR, cross platform tools, equivalent effective wellbore radius concept, etc. are being incorporated in simulating hydraulically fractured reservoirs.
The objective of this paper involves in presenting a critical review of the LGR and PeBi techniques utilized by the industry for dynamic modelling and simulation of the hydraulically fractured wells. One of the most critical issues in simulation studies is saving run time, in order to achieve this feat, many different methods as mentioned above have been incorporated till date in the industry. Optimizing the hydraulic fracture model, to save run time, trial and error method has been utilized. A tight reservoir model is used to incorporate sensitivities in gridding techniques and well placement.
Is Waterflooding the Clearfork Viable? Using Reservoir Simulation and Analog Data to Overcome High Uncertainty
Authors: Edwards Sara 
Published: October 2017

Abstract
Potentially generating an estimated $1.3 million in net present value, a proposed pilot waterflood in the Permian Basin of West Texas was determined to be technically and economically viable by using a reservoir model and analog data. Located in Winkler County, the lease has produced conventionally from various formations since its discovery in 1944. Primary production from the prospective waterflood interval, the Clearfork, began in 1994, and the daily oil rate has since declined 95%. At the current decline rate, commodity price, and operating expenditure, the lease is expected to become uneconomic by Spring 2017.
An analysis was conducted to determine the technical and economic viability of implementing a waterflood of the Clearfork formation to extend the life of the lease. A reservoir model of the field was created and history matched to validate reliability before predicting reservoir response to the pilot waterflood.
A secondary independent analysis used an offset operator's Clearfork waterflood as an analog to generate a production forecast using dimensionless curves, and the results confirmed the numerical model forecast. The predicted reservoir response using both methods revealed that implementing this project would result in over 40 MBO net reserves per producer. Economic analysis indicated that the project would be viable at $51/bbl oil price.
Investigation of the Optimum Production Strategies for the Economic Recovery of Gas Condensate Reservoirs with Different Aquifer Strength
Authors: Fawzy Farah 
Published: October 2017

Abstract
Gas condensate reservoirs are characterized by the surface production of both natural gas and light oil which is called condensate. The economic value added in the recovery of the gas condensate reservoirs makes key considerations in developing optimized production strategies for optimum oil recovery. Oil recovery from gas condensate reservoirs can be enhanced by maintaining the reservoir pressure above the due point pressure. This paper investigates the effect of varying the production rates on oil and gas recoveries from a gas condensate reservoir in the presecmce of a water aquifer with varying strength. The paper concludes production guidelines for the economic recovery of gas condensate reservoirs in the presence of a strong and a weak water aquifer.
Impact of Reservoir Mixing on Surfactant Slug Size Optimization
Authors: Galimberti Evan 
Published: October 2017

Abstract
Surfactant flooding is a common enhanced oil recovery technique that has been researched for its scientific potential, but inhibited by its economics. This method relies on greatly reducing interfacial tensions between phases, allowing the displacement of previously immobile oil. For this process to succeed on an industry scale the high chemical cost involved must be outweighed by the increased oil production. One way to decrease the cost of surfactant chemicals, is to ensure the slug sized used is no larger than necessary. Accounting for the physical mixing in a compositional simulator plays a large role in determining the optimum slug size and success of the project.
Mixing occurs when the surface area between concentration gradients expands, increasing diffusion. In reservoir simulators, the amount of numerical dispersion can alter greatly depending on the model structure. To achieve a model reflecting a physical case, the mixing influencing surfactant concentrations must match the mixing occurring in the reservoir. The more heterogeneous a reservoir is, the more physical mixing will occur as the area of contact increases significantly with length traveled. Because dispersion is scale dependent, matching the physical amount of dispersion by varying the gridblock size can be challenging. As a numerical model is upscaled, the physical mixing decreases while the numerical dispersion associated with the grid increases.
To show the effects of the changing gridblock scale and heterogeneities, two dimensionless parameters were used to test various models for their optimum surfactant-polymer slug size. Both one and two-dimensional models were created in UTCHEM to simulate a surfactant injection process by altering one of the dimensionless parameters, and observing the optimal slug size. A matured water flood was followed by chemical flooding. The optimal was found using the incremental efficiency of the surfactant, taking the incremental oil recovered divided by the mass of chemical injected. The incremental efficiency curves display a single optimum for each case, which closely tie to the economic potential of the process. With knowledge from core flood experimentation, when looking to apply at field scale, it is vital to account for the difference in the mixing effects. This work could result in a better understanding of the optimal surfactant volume needed, greatly reducing chemical costs.
Pore Structure Analysis Using Subcritical Gas Adsorption Method
Authors: Murugesu Manju Pharkavi 
Published: October 2017

Abstract
The oil and gas industry has been tapping into tight reservoirs with low permeability and porosity. This calls for methods to enhance our understanding of tight reservoirs, such as shale. A large percentage of gas in place in shale reservoirs is in the form of adsorbed gas on the surfaces of pores. The pores of shale reservoirs range from micro-, meso- to macropores. Small pores contribute to large surface area accessible for adsorption, emphasizing the importance of studying pore structure in nanoscale. Subcritical gas adsorption isauseful methodto characterize pore structures in nanoscale in terms of quantifying pore volume, determining the presence of micropores, predicting pore geometries and the accessible surface area for adsorption.
This paper discusses results obtained from running adsorption on samples of four different formations: Niobrara shale, Lokpanta oil shale, Hawaiian basaltic rock and Berea sandstone. Some of the results used to both qualitatively and quantitatively study pore structures are isotherm, pore size distribution and specific surface area. These results both affirm and debunk generalizations tied to certain formations. For instance, sandstone typically has large grains and this is confirmed by the zero micropores shown in both its isotherm and pore size distribution. On the contrary, some of the basaltic rocks are expected to have highspecific surface area due to its high clay content, yet the samples showed low specific surface area instead. This informs the lack of information available on the sample, thus, initiating more tests to understand other factors that may be causing low specific surface area. Moreover, Lokpanta oilshale does not have any external information provided, but the isotherms and pore size distribution help to intuitively grasp the image of the samples' pore structures. This paper illustrates how best to analyze and compare the experimental results.
Subcritical gas adsorption makes it easy to picture pore structures at nanoscale. Understanding pore structures, specific surface area available for adsorption and micropore volume for storage purposes is crucial for applications, such as carbon capture and storage (CCS).
Determining The Resistivity Anisotropy of High-Resistivity Sediments, Based on Lateral Logging Sounding Data From Vertical Wells
Authors: Petrov Aleksei 
Published: October 2017

Abstract
In studying and development of unconventional reservoirs, it is important to know vertical component of resistivity. This information can be obtained by HRLA or Rt-Scanner type devices, but due to low oil prices, using of them in Russia is becoming economically inexpedient. This leads to the necessity to develop a quantitative interpretation of the data of traditional Russian electrologging methods, which can provide information of the structure and properties of deposits with minimal cost. In vertical wells, in high-resistivity deposits similar to the Bazhenov formation, gradient sondes are sensitive to anisotropy, which was shown by the results of modeling and interpretation of signals on a one-dimensional cylindrical-layered model (Sukhorukova et al. 2013). A set of gradient sondes with different lengths is included in the equipment of the lateral logging sounding (BKZor also Russian lateral logging) method and is often used in Russia in the vertical wells survey. However, the application of the method is difficult if the thickness of the beds is small.
In this paper, I propose a technique for processing BKZ data measured in complicated geological medium with small thicknesses of interlayers. To increase the accuracy of determining the parameters of an anisotropic medium, a two-dimensional geoelectric model and finite-element algorithms for solving direct problems are used. The geological object of study is a major source of unconventional oil in Russia – the Bazhenov formation, but the proposed technique is applicable to other objects. Based on the results of data processing for 18 wells from the Fedorovskoe and Russkinskoye fields, the features of resistivity anisotropy coefficient distribution by depth at intervals of the Bazhenov formation have been revealed.