bluuebunny/crossref_metadata_2025_split huggingface dataset:
Models Cross-Validation as a Best Practice for Optimization of Well Stimulation
Authors: Alexander Bochkarev , Dmitriy Chernyshev , Narkes Gaysina , Andrey Lisitsyn 
Published: November 2020

Abstract
Development of low-permeable oil reservoirs with complex bedding often requires application of production stimulation methods such as hydraulic fracturing.
Success of well stimulation greatly depends on quality of geomechanical and hydraulic fracture models. Several different workflows can be used to build a certain model when the input data available are necessary and sufficient. However, in the absence of some of the key data, it is necessary to use rational assumptions instead, but doing so automatically regards model output as probabilistic.
This paper concentrates on steps necessary to constrain initial assumptions made within models and demonstrates the result obtained. We present an integrated workflow used for cross-validation of geomechanical and hydraulic fracturing models based on production history match as a constrain.
Relatively thin 35 deg API oil-bearing ∼ 0.3 mD hydrostatically pressurized zone, represented by interbedding of heterogeneous sedimentary layers of gross height of ∼ 15 m out of which about 5.5 m is pay, with argillitic barriers at top and bottom (see Fig. 2) has active water-bearing formation 45-50 meters above. Production history available for stimulated horizontal wells has shown a significantly increased water-cut compare to one expected from the zone of interest.
Earlier frac company stress models were made by tying pressure gradients - "regional experience" - to gamma ray and SP logs and attributing E, KIc to lithology. These fracture models were consistently showing hydraulic fracture containment by barriers of the target zone and, thus, fracturing into water zone was not viewed as a highly probable cause of an increased water cut.
Our target was to resolve the water cut problem by means of geomechanical and retrospective hydraulic fracturing modeling. These two models were initially built on incomplete data due to the absence of:
pore pressure measurements mechanical properties (static Young's modulus) from core analysis.
The models were then cross validated by constraining on production history while utilizing Young's modulus as variable. PEBI-grid based reservoir simulator is fully coupled with finite difference planar full-3D hydraulic fracturing simulator and allows direct transfer of fracture geometry (conductivity) for multiphase flow simulation.
Chemical Sand Consolidation Design in Jasmine Field: Lessons Learned and Critical Success Factors from an Operator Point of View
Authors: Dachanuwattana Silpakorn , Prasongtham Pattarapong , Kulchanyavivat Sawin , Chigbo Ikenna , Sreeroch Asadawut , Grassian David 
Published: November 2020

Abstract
The Jasmine oil field, in the Gulf of Thailand, has several pools of unconsolidated sandstone reservoirs. Multi-zone completion is usually deployed in these reservoirs, however, sand control in this completion type could be a challenge. Several sand control techniques were evaluated and the most promising strategy was found to be chemical sand consolidation treatment. In the design phase, the most critical challenge was to determine the optimal and safe chemical recipe and placement technique.
A single chemical recipe optimized for all of the reservoirs was achieved, yielding an unconfined compressive strength (UCS) of at least 500 psi while retaining a permeability of 40%. Bullheading was selected as the placement technique. To minimize contamination of the chemical with annulus fluid, we designed to shorten the distance between the packers of each completion zone. Cut-to-release packers were used instead of pull-to-release packers to mitigate the concern of unwittingly unsettling the packers. A risk assessment was conducted to cover all aspects of the job. High risk activity like pumping flammable fluids at high pressure was specifically singled out and special mitigation was put in place to ensure a safe execution of the activity. Some other mitigations such as minimizing nearby hot surface areas, real-time monitoring of oxygen levels, and purging the mixing system with CO2 were also considered.
This paper provides a case study for chemical sand consolidation treatment from the view of an oil company and covers the full lifecycle of the application from concept selection to the finalized procedure, taking into account both technical and operational considerations. This research contributes to the public body of knowledge within the oil and gas industry with regards to an emerging technique for sand consolidation.
Breakthrough Formulation of Novel Modified HF Acid System: Realizing Remarkable Value in Sandstone Reservoirs
Authors: Mohd Jeffry Suzanna Juyanty , M Shafian Siti Rohaida , M Hatta Siti Aishah , Madon Bahrom , Mohamad Khairul Idzwan , Adlan Ezamy 
Published: November 2020

Abstract
Matrix acidizing is one of the most common well stimulation methods in Malaysian brown fields. Formation damage caused by fines migration has been reported to be among the main reason for productivity decline. The need to conduct acid stimulation arises when the initial rates of the wells are below expectation or when the productivity of the reservoir drops significantly. Various mud acid formulations have been used to treat the wells from the past until recent years. However, some well treatments resulted in low success rate especially for reservoirs with vast variation and complex formation mineralogy. This highlights the need for modified acid recipe from the conventional mud acid system. Mud acid systems are often highly corrosive, resulted in unwanted secondary precipitation and require multiple additives during the treatment.
This paper highlights the evaluation and comparison of the novel Modified HF acid against conventional mud acid system through core flooding tests. Multiple cores with various mineralogy were tested. The laboratory test showed that the Modified HF acid system able to generate better permeability improvement compared to mud acid systems. The modified acid recipe gradually sequestrates the major iron minerals throughout the injection to avoid unwanted secondary or tertiary precipitation that could damage the formation. Subsequently, the chemical was successfully piloted in two fields and replicated in other fields across Malaysia. The field applications proved that the novel Modified HF acid system generated outstanding results in production gain and improved the total economics of the project. The novel acid recipe can be an alternative solution when simpler acid systems are favored with lower treatment cost. This chemical is also beneficial for wells that located in small platforms or jackets where minimal amount footprint is available during job execution.
Methodology to Derive Gas Oil Ratio and Other Formation Evaluation Applications of Downhole Ultrasonic Sound Speed Formation Tester Measurements
Authors: Torlov Vladislav S. , Amin Asif , El Sharaky Mohammed 
Published: November 2020

Abstract
The paper presents a methodology and results of a study to derive the gas-oil ratio (GOR) of oil in situ based on downhole ultrasonic sound speed formation tester measurements. Authors provide several cases as a reference for in-situ fluid acoustic measurement values, and cleanup profiles in various borehole and downhole settings, to illustrate their benefits for formation testing as well as other geoscience applications.
Formation tester dynamic fluid measurements of analysis of 47 samples from 25 wells were assessed. Reference GOR measurements were collected from different sources. The relationship between in-situ sound speeds corresponding to reference GOR was assessed and showed strong correlation within the investigated range. To enhance estimation accuracy, another two methods of deriving GOR using fluid slowness, downhole condition parameters, and computed pseudo-density are presented.
The assessment of formation tester fluid slowness data showed its consistent association with live oil GOR within the studied range (~20-1,500 scf/bbl). Further increase in GOR showed change in the relationship trend. Several methodologies of GOR estimation are discussed including multiple linear regression using fluid slowness, in-situ pressure, temperature, and linear regression with estimated pseudo-density of a fluid. The multiple regression output showed slightly better match with laboratory data. Results of other data modelling approaches are also discussed.
The proposed GOR evaluation methodology is based on acoustic surveys made downhole without phase separation. The results are available at the time of formation testing cleanup and fluid sample capturing stages. The additional benefit of the method is to aid in assuring fluids are maintained in single phase for collection of representative samples.
Machine-Learning Distributed-Temperature-Sensing-Based Pipeline Leak Detection
Authors: Sfar Zaoui Wissem , Lauber Thomas , Pohl Clemens , Kerk Michael , Glaeser Thomas , Jelinek Wolfgang 
Published: November 2020

Abstract
In this paper, we present results of field trials using a novel machine learning (ML) pipeline leak detection algorithm based on the distributed temperature sensing (DTS) technology. The installation is based on a buried, 9km-long pipeline in Germany. The transported medium is wet oil with a temperature varying in the range of ~20°C–35°C. A multimode fiber optical cable (FOC) is laid at ~10 cm distance from the pipeline and is connected to a Raman-based DTS system. For verification, the leak test setup is composed of a water tank, heater, pump, and an injection pipe introduced on top of the pipeline at an unknown location for the DTS system, thus performing blind testing. The water was heated to 33°C (TEST1) and 19°C (TEST2) to simulate the temperature range of the transported medium and injected at a release rate of 36 L/h (TEST1) and 20 L/h (TEST2). The DTS system was adjusted to automatically alarm when the evaluated temperature deviation reaches 3°C with 3 confirmations. The ML alarm evaluation method was able to detect the anomaly at the test position after only 0.8 barrel (TEST1) and 1.4 barrel (TEST2) of total released fluid volume. In comparison, classical gradient-based approaches would require up to 5 times higher alarm threshold, which may not be reached due to the low temperature difference of the oil to the ground.
Assessing the Feasibility of Deep Eutectic Solvents For CO2 Capture From Molecular And Process Modeling
Authors: Alkhatib Ismail , Alba Carlos , Bahamon Daniel , Llovell Felix , Vega Lourdes 
Published: November 2020

Abstract
The soft-SAFT equation of state is employed for the screening of deep eutectic solvents (DES) for CO2 capture based on key performance indicators, namely, CO2 absorption capacity, and enthalpy of absorption. This work belongs to a long-term project on assessing the adequacy of advanced EoSs (soft-SAFT) as a tool for the evaluation and design of alternative solvents for CO2 capture.
The models for the pure DESs and their mixtures with CO2 are validated with experimental data, and subsequently used in a fully predictive manner to calculate the thermophysical properties needed for evaluating solvent performance. Results demonstrate that under the same operating conditions, [TBA][Cl]:LA (1:2) is the most promising DES in terms of amount of CO2 absorbed and enthalpy of absorption. However, the comparison of these solvents to 30 wt.% aqueous MDEA solution shows that the promise of DESs is far from adequate in terms of CO2 solubility, being 13 times lower than that obtained with aqueous MDEA. Nevertheless, DESs show a clear advantage in terms of lower enthalpy of absorption, being 3 times less than aqueous MDEA, along with the absence of water as a co-solvent. The collection of the acquired results confirms the reliability of the soft-SAFT EoS as an attractive and valuable screening tool for CO2 capture and process modelling.
Multi-Stage Frac Sleeves Completion Risk Matrix - A Quantitative Approach to Minimize Stuck Incidents while Deploying Completions Across Horizontal Slim-Holes
Authors: Vega Roberto , Simmons Yvan , Shakeel Muzzammil 
Published: November 2020

Abstract
Drilling and completing wells for hydrocarbon production comprise the major cost of well operations. Slim-hole drilling can significantly reduce drilling costs, making low producing reservoirs economically viable. However, a number of challenges are associated with slim-hole wells. A major challenge encountered while deploying lower completions in long horizontal slim-hole wells is stuck pipe, as the wellbore diameter is less than six inches, allowing restricted clearance between the wellbore and completion equipment. Stuck pipe incidents can cause significant non-productive time (NPT), additional high costs, and the possibility of compromising the well objective.
Stuck pipe incidents may require sidetrack operations in the worst cases, which may considerably change the planned well design and delay the overall project, along with increasing costs. Drilling in the minimum stress direction with heavy mud weight and high overbalance pressure adds to the challenge in deploying completions in HPHT slim-hole wells. While deploying the lower completions in slim-hole wells, many factors come into play and each factor has a critical role in the success of the operation.
After conducting a detailed study on several HPHT slim-hole gas wells in Middle-East region, a risk matrix was developed for a specific well-bore diameter, by identifying some common variables. Based on potential chance of occurrence, a certain value was assigned to each variable. The risk mitigation plans are driven by the risk matrix variables. Using this risk matrix, the occurrences of stuck pipe incidents in critical HPHT slim-hole wells that initially tend to have high chances of stuck pipe were significantly reduced.
The risk matrix presented in this paper successfully mitigated stuck pipe incidents from occurring and has saved millions of dollars in associated costs. The matrix played a key role in operator's drilling operations and was adapted in operations as an important tool to evaluate final wellbore conditions prior to selection of the optimum completion type. This paper presents a highly effective risk matrix that significantly minimizes stuck pipe incidents during drilling/completion operations of slim-hole gas wells.
Integrated Multi-Frequency Characterization of Sandstone Rocks
Authors: San Roman Alerigi Damian , Alvarez Jose Oliverio , Batarseh Sameeh , Al-Khaldi Bander 
Published: November 2020

Abstract
The ultimate goal of our work is to develop an electromagnetic multi-frequency integrated system to enable real-time and in-situ characterization during high power electromagnetic (HPEM) operations, e.g. logging while lasing (LWL) or logging while microwaving (LWW). The sensing platform should provide information about the environment, the substrate, the near-wellbore (ahead of the beam), and the process. Real-time sensing is necessary because HPEM operations are faster and avail more control to target the electromagnetic energy to attain a specific purpose. Thus, the sensing systems must be compatible and operate simultaneously with HPEM radiation. In this context, electromagnetic multi-frequency characterization could provide valuable information to evaluate the near-wellbore volume, fluids, and the environment. This paper introduces essential spectrometry components and analytics.
The experiments reported focus on the characterization of tight-sandstones rocks from different reservoirs. The characterization process used various tools: microwave and radio-frequency resonators, Fourier-transform infrared reflectometry (FTIR), porosimetry, and sonic reflectometry. Five resonances were measured using a custom-made microwave resonator with measurements at frequencies between 980 MHz – 3.5 GHz. As this comprehensive characterization evolves, it will use machine-learning algorithms to display the correlation between the electromagnetic response of the material and other rock properties; e.g., clay content, saturation, porosity, and mechanical properties.
FTIR and low-frequency impedance enable the characterization at surface and bulk volume, respectively. The experimental results confirm the correlation between some chemical, mechanical, and electromagnetic properties of materials. These relations could be used to derive clay content, total organic content, maturity, saturation, among other material properties. The results of this characterization contribute to the growing database of electromagnetic properties of rocks under different configurations. The expectation is that this information can be coupled with statistical and machine learning algorithms to build edge neural engines for subsurface characterization and HPEM tools.
Electromagnetic tools and methods for subsurface allow characterizing the formation with high accuracy and resolution. The combined results and algorithms could enable the estimation of rock type, porosity, saturation, and other properties while conducting HPEM operations. The information provided could eventually enable automated systems and logging-while-lasing. This work presents the foundational blocks to achieve this and guide the development of subsurface laser technologies.
A New Technique for Common EoS Model Development for Multiple Reservoir Fluids with Gas Injection
Authors: Aoki Takeshi , Furuta Tetsuro , Leekumjorn Sukit , Azeem Shaikh Jawad , Schou Pedersen Karen , Alobeidli Abdulla , Mogensen Kristian 
Published: November 2020

Abstract
A new technique is presented for the development of a common equation of state (EoS) model for multiple petroleum reservoir fluid compositions counting heavy gas condensates, near-critical fluids and black oils. The basic idea is that the phase behavior of a reservoir fluid to a large extent is determined by its critical point. This is not only the case at near-critical conditions. An EoS model matching the critical point of a petroleum reservoir fluid will in general also provide a good match of routine and EOR PVT data for both gas condensates and black oils. A measured critical point will seldom be available, but can be estimated from other available PVT data. The new technique is exemplified through the development of a 9-component common EoS model for 21 H2S rich reservoir fluids, 3 near-critical fluids, and 18 black oils. All 21 fluids had routine PVT data and 11 had solubility swelling data. Using the available PVT data, an approximate critical point was determined for each reservoir fluid composition. The critical point and the saturation point pressure at the reservoir temperature were the only data tuned to when developing the common EoS model. With this simplified method, the time spent on developing a common EoS model for a large number of fluids can be significantly reduced. The method provided a good match of the PVT data for all 21 reservoir fluids including the shift from bubble point to dew point on the swelling curve for the black oil compositions that had solubility swelling data.
Three-Phase Numerical Solution for Jet Pumps Applied to a Large Oilfield
Authors: Merrill Robert , Shankar Vivek , Chapman Thomas 
Published: November 2020

Abstract
The Mangala oil field in Barmer, Rajasthan is one of the largest onshore fields in India. The field is under an active polymer flood with over 300 wells injecting &gt;400 kbwpd. Jet pumps have been the main mode of artificial lift for the field since production commenced in 2009. The jet pumps are "reverse circulation" type with the power fluid (water), pumped down the annulus. Despite their low efficiency, jet pumps are ideal for Mangala because heated water is used for the circulation fluid which avoids wax deposition in well tubulars.
Simple performance curves, often used in commercial packages, work well under two phase liquid only or low GOR conditions. With high gas volume fractions and higher drawdowns, the additional complexity of critical flow is introduced; this occurs when the fluid velocity reaches the speed of sound within the jet pump. These conditions are often encountered in the Mangala pumps, and many jet pump solutions become grossly inaccurate when used for these conditions.
A field-wide network model is being used for production optimization; the model employs coupled power fluid and production network systems. Given the size of the power fluid network, an accurate and fast method for jet pump performance under three phase conditions is a prerequisite to the modelling of both well behavior and jet pump sizing.
This paper presents a full solution of the fundamental jet pump equations, which are based on Bernoulli’s principle and the conservation of momentum. The method follows the classic solution presented by Cunningham (1970, 1995), which made simplifying assumptions of perfectly incompressible liquids and ideal gases. The proposed technique eliminates these simplifications, making the solution applicable for the situations commonly encountered in the Mangala field.
Existing jet pump models for Mangala are based on spreadsheet solutions. These solutions are slow and are practical only for the sizing of individual jet pumps. The new model presented in this paper solves the fundamental equations using numerical techniques and properly accounts for high compressibility fluids, multiphase flow and critical flow. The model was written in Python, which is an object-oriented language well suited to modeling the individual components of the system. The model solves the integrals involved in the revised Cunningham equations, using Newton-Raphson techniques to solve the equations iteratively. The model is used to generate complete (and complex) VLP curves in standard formats which can then be used directly with network models. The new model executes 25-100 times faster than the previous spreadsheet model.