bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparative Study on Fluid Composition Determination from Near Infrared Spectra Using Deep Convolutional Neural Networks and Partial Least Squares Regression
Authors: Weinzierl W. , Cartellieri A. , Schapotschnikow P. 
Published: February 2024

Abstract
The conventional approach to fluid characterization using partial least squares (PLS) is considered a benchmark in chemometric fluid analysis. Complementary, convolutional neural networks (CNN) have been shown to provide comparable discrimination capabilities. In a comparative study, the performance for quantitative characterization of downhole fluids using near-infrared (NIR) spectra has been evaluated. Both methods are used to predict the fluid composition in fractions of water, gas, oil, and mud. PLS is a statistical technique designed to model the relationship between two sets of variables, in this case between the spectrum and the composition. It relies on the representation of the variables in a multidimensional latent space. Usually, the inference consists of three steps. First, the input (spectrum) is linearly projected into the latent space. Second, the output is calculated in the latent space. Finally, the composition is computed as a linear transformation of the latent output. Instead of using PLS for end-to-end inference, only its first step has been used for feature extraction. By using the first latent dimension for each component, features were obtained that can be conveniently associated with water, gas and oil respectively. These features are then used together with the constant baseline in a multinomial logistic regression to obtain fractional components of the present fluid types in the NIR spectra. The baseline is primarily needed for mud detection. In parallel, several CNN models were trained for fluid characterization based on NIR spectra on processed and raw data. Hyper-parameter optimization of the CNN's is performed using a tree structured Parzen estimator to obtain a best trial configuration. Scheduling of the optimization loop yielded improved inference results. Quantitative comparison of the PLS and CNN models was performed using a k-fold approach. This allows for a direct comparison of the methods performance given as input spectra of pure and mixed fluids. Both methods show high accuracy when predicting pure components. The root mean square error (RMSE) is consistently larger for PLS. The CNN models generally show larger variance in the prediction for mud, with minor fractions of water, gas and oil being inferred. A quantitative comparison of two methods in chemometric fluid analysis shows an overall improvement of predictive power for a set of deep CNN in respect to the PLS approach. Improved inference is achieved using raw NIR spectral data. This is particularly interesting as no further pre-processing of the spectra is required, thereby minimizing porting efforts in the development of embedded applications.
Maximizing Value From D Field Via Safeguarding Hub Reserves and Resources For Sustainable Supply and CCS Development To Peninsular Malaysia Ecosystem
Authors: Faiz M Faridyl , Rong Tee Zhao , Samsudin Yuzairy B , Ramli Zuhairi 
Published: February 2024

Abstract
D Hub is one of the key offshore gas hubs currently receiving gas from several producing fields for onward supply to domestic Peninsular Malaysia customers via an existing onshore gas terminal and pipeline network. Due to production decline as well as techno-commercial challenges of future field tie-ins, D Hub was expected to reach its Minimum Compressor Limit (MCL) of 70 MMscf/d by end of 2022 below which the hub is no longer operable.
Recognizing the impending cessation of D Hub and storage availability in the range of 1.2 – 1.7 Bscf at its depleted anchor field, Carbon Capture and Storage (CCS) has been identified as a promising option to repurpose the gas hub into a CCS hub. Moreover, interests in low carbon industry are accelerating in Malaysia, with CCS as one of the key enablers to meet Net Zero Carbon Emission (NZCE) commitments.
The technical team has also identified seven (7) solutions ranging from short-, mid- and long-term to further sustain D Hub existing operations either by lowering down its turndown limit and/or maturing new gas supply developments. The success of either of these initiatives however will further push the timing of the CCS hub conversion.
The paper is split into three (3) parts: -
In the first part, the solutions identified to extend D hub as gas hub will be described in detail. Short term solutions to ensure D Hub can continue operation includes the commissioning of Module Recycle Valve (MRV), lowering down D Hub plant pressure and production enhancement for the existing producing fields. Mid-term approaches consist of maturing projects with higher technical certainties and restaging the compressor to a lower turndown limit while waiting for a major Gas Cap Blow Down (GCBD) project to achieve higher project maturation (long term solution).
The second part will discuss the CCS Hub key challenges and considerations, mainly revolving around CO2 injection timing at D Hub.
Then finally the last part of this paper will outline the conundrum faced in choosing whether to further extend the gas hub at the expense of CCS deferment or an earlier CCS but at the risk of future gas developments being stranded.
New Generation Fracturing Fluid with Superior Proppant Transport and Oil Displacement Functionalities
Authors: Lin Genyao , Huang Jiangshui , Richardi Bryant , Yu Stephanie , Li Jianshen , Liu Fuchen , Lin Lijun 
Published: February 2024

Abstract
Multifunctional fracturing fluid is desirable in the oil and gas industry as it can simplify hydraulic fracturing operations and reduce environmental impact. Traditional high-viscosity fluids, like borate crosslinked fluid, can effectively transport proppant to keep fractures open but can constrain fracture length and damage the proppant pack. Conversely, low-viscosity options like linear gels, can extend fracture length and facilitate secondary fractures, but have limited proppant carrying capabilities. Recent efforts have attempted to combine fracturing fluid with surfactants to achieve both hydraulic fracturing and improved oil recovery. However, these efforts require multiple additives and still lack sufficient proppant transportation. This study introduces a new generation fracturing fluid combining superior proppant transport and oil displacement functionalities, formulated with a unique polymer containing chemically bonded oil displacement surfactant.
The new fracturing fluid was evaluated using a range of tests, including static proppant suspension test, rheology test, coreflood, regained conductivity and oil displacement tests. The static proppant suspension test compared the new fracturing fluid with a linear gel. The fluid's rheological properties were measured using an advanced rheometer. The spontaneous imbibition Amott test was conducted to appraise the fluid's oil displacement properties. The coreflood and regained conductivity studies were conducted at 160°F to evaluate the fluid's formation and proppant pack damage.
The new generation fracturing fluid excelled in all tests studied. In the static proppant suspension test, it suspended the 20-40 mesh ceramic proppant much longer than the traditional guar-based fluid. The rheology test revealed that the 0.3wt% fluid's storage modulus G’ is higher than the loss modulus G" across the whole spectrum of frequency tested, signifying high elasticity of the fluid. The spontaneous imbibition test demonstrated the new fluid increased the relative oil recovery rate by 12.1% compared to the control polymer. The coreflood results showed an 85.7% regained permeability for the 0.4wt% new fluid. The conductivity study showed a 94.7% regained conductivity. These results demonstrate that the next generation fracturing fluid can not only offer superior proppant transport capability but also it can be easily broken down by traditional breaker and then release the oil displacement surfactant to achieve oil displacement functionality. These features make the new fracturing fluid an excellent choice for hydraulic fracturing applications with less freshwater usage and reduced environmental impact.
Application of a New Imaging Technique in Thin Beds Analysis / Sand Counting of Clastic Reservoirs in Oil Base Mud Environment
Authors: Ighodalo Endurance , Idris Umar , Hassan El-Saied , Al Mubarak Mustafa Ahmad 
Published: February 2024

Abstract
The identification and quantification of thin bedded net reservoirs is very challenging. Accurate pay thickness requires the integration of high-resolution data. This paper presents an accurate pay estimation method in wells drilled with Oil Base Mud (OBM) across clastic reservoirs where high-resolution image and true formation resistivity logs were utilized to perform advance thin bed analysis.
OBM image technology provides photorealistic borehole image, electrical conductivity, and dielectric permittivity. Gauss-Newton algorithm is applied to generate button standoff, formation resistivity and dielectric permittivity images. Also, the new Hayman factor image analysis associates colour spectrum to the various rock and fluid types in the formation. This was used in estimating the reservoir heterogeneity, including open or closed fractures and more importantly the thin beds sand counting. The true formation resistivity was utilized to optimize the saturation / pay across these thin beds. These static measurements are integrated with dynamic results from the formation testing.
Quantitative analysis of Advanced OBM Image data across thinly bedded clastic reservoirs has been conducted. Lamination analysis of the high-resolution image data was performed to understand the lamination density and thickness. The inverted resistivity image was applied to differentiate the good quality sand from degraded facies. Both analysis results were integrated with the true formation resistivity to evaluate accurate net pay in thinly bedded sands and subsequently confirmed by hydrocarbon samples.
The technique presented in this paper reveals new and accurate method to evaluate and estimate the amount of reservoir heterogeneity. These will help in a more precise estimation of net sand / pay count in thinly bedded sands.
An Integrated Engineering Approach Aiding the Delivery of the Challenging Build-up and Lateral Sections in an Exploration Field
Authors: Baghdadi Ahmed , Sen Souvik , Chakrabarti Prajit , Vossen Johannes , Malik Kashif , Salmin Ivan , Bashir Munir , Bakr Ahmed 
Published: February 2024

Abstract
This study presents a case of successful delivery of a challenging build-up and lateral section through heterogenous lithologies from an exploration field in the Middle East using an integrated multidisciplinary approach of optimization, planning and execution. Based on the offset well drilling experiences, poor ROP, mechanical instability, and differential sticking against some of the highly porous and permeable carbonate reservoirs were identified as the main drilling challenges impacting delivery for the 8-1/2" and 6-1/8" sections parallel to the regional minimum horizontal stress azimuth. Comprehensive geomechanical modeling and wellbore stability analyses were carried out to recommend a safe mud weight window to tackle mechanical instabilities. Utilizing an optimum drill bit design ensured improved durability, trajectory control, a higher rate of penetration and resulted in a 33 % performance improvement on the field average. Drilling fluid chemistry was optimized with required bridging concentrations based on particle size distribution assessment. The 7" liner shoe placement and drilling practices were optimized based on the offset well events and subsurface characteristics to ensure successful execution of the landing section. Real-time monitoring of the LWD data (includes density imaging), aided by right-time geomechanical advisory support ensured successful well delivery without any significant drilling challenges. As a result of the implementation of this systematic and integrated multidisciplinary approach, both sections achieved geological objectives with zero NPT. The well was delivered 8.6 days ahead of the plan, and 14 days ahead of the best similar well.
Spiral Hole Moderation Enhances High-Resolution Borehole Image Interpretation Across Fractured Carbonate Reservoirs
Authors: Altarouti Alawi , Alotaibi Abdullah , Guerreiro Prudencio , Fakhrylgayanov Ayrat , Dolan James 
Published: February 2024

Abstract
Dynamic phenomena while drilling such as borehole spiraling or corkscrewing can create a physical imprint on the borehole surface, which mask fine features of imaging. During a drilling campaign in a carbonate reservoir using logging-while-drilling technology, corkscrewing was severely impacting the ultrahigh-resolution borehole image quality. As a result, fracture identification was affected that had significant implication on reservoir characterization, description, and hydrocarbon recovery strategies. Consequently, a collaborative project was initiated to find a solution to overcome these phenomena.
The impacted wells in the field and other nearby fields with similar formation characteristics were analyzed at first to find commonalities. Based on this investigation, a suggested solution to eradicate the spiraling was to reduce the interaction forces and minimize the adverse effect on the directional drilling capacity of the bottomhole assembly (BHA). A new bit design was required with design elements expected to mitigate or minimize borehole spiraling. With it, the bit gauge length was increased as well in successive wells combined with drilling parameter optimization. Drill bits from several vendors were used to study the impact of different bit designs.
The results from the detailed technical investigation indicated that borehole spiraling resulted from the bit-to-formation interaction. The testing of different bit gauge lengths and shapes was aimed at reducing the bit-to-formation interaction. On the other hand, the new bit design assessment raised another challenge, which was the BHA steerability and control. An increase in gauge length was expected to reduce the spiraling but potentially impact the steering capability negatively while drilling the well. Hence, a thorough design of the bit and BHA was performed to ensure the well steerability would comply with maintaining optimum well placement criteria. Each increase in gauge length minimized the severity of the borehole spiraling effect. The critical factors determined to reduce spiraling were the gauge design and length. Consequently, the borehole image quality obtained was significantly enhanced, enabling detailed fracture identification and reservoir characterization. Additionally, the enhancement in borehole image quality enabled openhole completion to be designed methodically to isolate conductive fractures with aim to extend well life, delay water breakthrough, and as a result maximizing reservoir sweep.
This paper presents the methodology and results of the bit design test to mitigate the presence of borehole spiraling. The quality of the ultrahigh-resolution borehole image was significantly improved, which enhanced the confidence in reservoir characterization, fracture modeling, and field development strategies such as completion design.
Impact of Surface Roughness on Rock Wettability
Authors: Aboushanab M. S. , Samad M. Abdul , Raza A. , Mahmoud M. , Al Kobaisi M. , Rahman M. M. , Arif M. 
Published: February 2024

Abstract
The wettability of the solid/fluid systems is an important property in several applications. The accurate determination of wettability in rock/fluid systems has a paramount role due to its fundamental influence on fluid distribution and the dynamics of multiphase flow in porous media. While various methodologies are available for the assessment of the wettability behavior of rocks, the goniometric approach, employed for contact angle measurements, is widely acknowledged for its direct applicability and appropriateness. This technique has the distinct advantage of facilitating wettability characterization for a broad spectrum of physicochemical conditions e.g., variations in pressure, temperature, and salinity.
Several investigations have reported contact angles under diverse conditions for various rock/fluid systems. However, contact angles often depict an inconsistency in terms of the observed wetting behavior of specific rock/fluid systems under identical conditions. One prominent contributing factor to these discrepancies is rock's surface roughness. Typically, smooth and polished rock surfaces are utilized for contact angle measurements, and this study depicts that ignoring the inherent surface roughness of rocks can have notable impact on its wettability.
This study analyzes the wetting characteristics of two distinct carbonate samples, each engineered to exhibit a spectrum of surface roughness values. Additionally, our investigation explores the impact of varying polish-abrasive sizes and types on both surface roughness and wettability, utilizing commercially accessible abrasives spanning a wide spectrum of dimensions, which include liquid silicon carbide (Si-C) and sandpaper. The results contribute to an enhanced comprehension of the mechanisms governing wettability fluctuations at the millimeter scale and thus explain the underlying mechanisms influencing wetting properties.
Development of Geomechanical Earth Model for New Wells with High Deviation Trajectory Plans in South of Iraq
Authors: Al-Asadi Yousif M. B. , Khan Danish A. , Abdi Hadi A. 
Published: February 2024

Abstract
The southern Iraq region has the privilege of having a group of the most important oil fields in the world. More than 3000 wells have been drilled in this region with different well designs, presenting major wellbore instability issues that includes caving, hole pack-off, stuck pipe and logging tools, hole enlargement, during drilling operation. Proper designing for any drilling campaign in these fields is the main step for achieving the targeted goals. Drilling the first boreholes with high deviation trajectory plan and new well completion design will require a consolidate geomechanical model as an essential tool for assessing drilling integrity, and guiding future well planning non-productive time.
The main objective of the current study is to construct high resolution 1D mechanical earth model (MEM) for new highly deviated trajectory plan developed recently in one of the fields using a wide array of input and calibration data. The generated 1D model was utilized to examine the Wellbore Stability using different failure criterion methods for evaluating drilling problems related to instability when penetrating through weak formations, then to determine the safe window of the mud weight for the wells with deviation above 75 degrees.
These analyses highlighted the change in drilling stability with well azimuth and inclination, which showed that drilling highly deviated borehole in the direction of minimum horizontal stress is different in the case of drilling with maximum horizontal stress direction The telling conclusion—from all the field observations collected so far and the 1D results obtained—is the need for raising mud weights and change the casing design in the highly deviated wells. The drilling campaign for future deviated wells in the studied filed improved by designing optimal mud weight and casing programs for any given wellbore trajectory.
Results and observations from this study, helps in designing the current and future drilling campaign by designing the optimal mud weight programs for any planned trajectory and drilling practices, and serves as a base for planning deviated wells aiming to reduce nonproductive times and increased drilling efficiency.
Sulfate-Based Scales: Why Sulfate Ion Concentrations Matter
Authors: Almulhim N. , Alotaibi F. , Rafie M. , Alrufail T. 
Published: February 2024

Abstract
Waterflooding is frequently applied in oil and gas reservoirs to sustain the reservoir downhole pressure and achieve a high rate of hydrocarbons production. The main challenge of water flooding is the potential to induce mineral scale depositions, especially when the injected water contains a high sulfate content. The objective of this paper is to determine the minimum threshold of sulfate contents present in the injected water that will not lead to mineral depositions through theoretical and experimental work.
This study will showcase scale simulation and laboratory experiments involving multi-compositional water interactions with various sulfate concentrations ranging from 100 to 5,000 ppm. The study scheme starts by water preparation for the proposed brines, followed by geochemical analysis using Inductive-Coupled Plasma (ICP) to confirm the physical and chemical properties. Afterwards, scale risk assessment was performed using ScaleSoftPitzer™ to evaluate the scaling tendency. Finally, static bottle tests are conducted for a 48- hour testing period at temperatures ranging up to 260°F using HPHT aging cells at different mixing ratios.
The scaling tendency assessment indicated a calcium sulfate and strontium sulfate precipitation when sulfate content exceeded 300 ppm. Although 5,000 ppm of sulfate content showed theoretically a low scaling index of gypsum and celestine, the scale mass was estimated to be nearly 2,500 and 500 mg/L, respectively at equivalent mixing ratio. Also, it was observed that as the sulfate content increases, the scale severity increases as well. The experimental compatibility tests reinforced the simulation findings, which showed similar result of inorganic sulfate-based scale precipitation that was observed after 48 hrs. testing time.
The paper shares a system approach for water compatibility assessment and provides different scenarios using both simulations and water-water lab tests to confirm these predictions. It will also highlight how to mitigate the potential risk of scale and formation damage during water flooding.
Emulsified Epoxy Resin for Mitigating Sand Production
Authors: Chang F. F. , Liang F. , Lee Christie , Berger Paul 
Published: February 2024

Abstract
Sand production from unconsolidated or crushed weakly consolidated formations due to high reservoir fluid flow velocity leads to operational problems and limits their potential. Many techniques are practiced by the completion and production engineers to combat such challenge. This paper discusses the development and testing of a novel polymeric resin formulation that consolidates sand grains to form a high regained permeability and high compressive strength rock matrix, allowing high production rate without sanding concern.
The new chemical solution utilizes a low viscosity water external epoxy emulsion to strengthens the bonding of sand grains while maintains flow capacity. The chemical formulation contains two components that can be batch mixed at wellsite, injected by coiled tubing or drill pipe, and shut-in in the formation to cure for 24 to 48 hours depending on the reservoir temperature from 200°F to 320°F. Unlike most of the currently used resin consolidation products, by which post flush is required to maintain opening of the pore space, the emulsion separates during the curing process with epoxy attaching to the sand surface while the water phase occupies the pore to help keep the flow path open.
Laboratory experiments in both water or oil saturated sand packs showed the treated loose sand are well consolidated with the unconfined compressive strength significantly greater than 1000 psi and the regained permeability up to 54%. No sand production was observed in the produced fluid at high flow rates. This paper focuses on the laboratory testing of the water external emulsified epoxy. The chemical mechanism and evaluation methodology are described.
Having the water emulsified epoxy resin system allows the convention water based diverting techniques such as foam to be used during treatment of long sections. Another benefit of the water based emulsified epoxy is its operation simplicity and safety. The flash point concerns for safe field operation is completely alleviated with this chemical formulation.