bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Comparison of Retarded Acid with Emulsified and HCl/Formic Acid Recipes for Carbonate Acidizing
Authors: Al Moajil Abdullah , Aljuryyed Norah , Alghamdi Saeed , Caliskan Sinan 
Published: November 2020

Abstract
Various acids and chemicals have been developed to achieve retardation properties to enhance oil and gas production. Improving acid retardation through emulsification or polymer gelling agents has drawbacks. Retarded acid recipes including HCl, organic acids, and/or chemical retarders showed comparable retardation efficiency. This paper aims to compare the performance of non-viscous retarded acids and benchmark them against emulsified acids (Hall-Thompson et al. 2020).
The proposed acid recipes are either a combination of HCl, formic acid with or without inorganic/organic retarders. Emulsified HCl acids at 15 wt% were prepared as a retardation baseline. Carbonate dissolution was assessed using solubility testing with calcite discs. Coreflood testing was conducted using Indiana limestone core plugs to assess the pore volume profile at temperatures up to 300 °F. This study was supported by Computed Tomography, to evaluate the propagation behavior as a result of the fluid/rock reaction.
The solubility calcite discs in the retarded acid recipes showed acid retardation comparable to emulsified acid. The surface tension values of retarded acid recipe were between 19.5-38.5 dynes/cm at 70-300°F. The coreflood results showed retardation performance comparable to emulsified acids at 200 and 300°F. The retarded recipes were capable to prevent nearly 1,500 mg Fe/L from precipitation in spent acid. The corrosion loss and pitting indices were within &lt;0.02-0.09 lb/ft2 using retarded acid recipes at 170-300°F (i.e., &lt;0.02-0.09). The optimum injection rates of retarded acid recipes were nearly 1 and 2 cm3/min at 200 and 300°F, respectively. The results obtained with HCl/Formic acid recipes showed generally competitive retardation performance compared to retarded acid recipes with limitations discussed in the paper.
New Novel Constitutive Model for Solid Production Prediction with Laboratory Test Validation
Authors: Subbiah Surej Kumar , Mohamad-Hussein Assef , Samsuri Ariffin , Jaafar Mohd Zaidi , Chen Yingru , Pearce Andrew , Paramanathan Rajendra Nath 
Published: November 2020

Abstract
Sand production can cause serious chaos at the wellhead and needs a proper geomechanical analysis to understand the failure and post failure mechanisms. Thus, a proper constitutive model (failure criteria) is required for this effort as most of the available failure criteria are not specially developed for sandstone. The post failure (Softening) part is not normally captured in many of the existing models. For this reason, a new elastoplastic constitutive model for sandstone has been investigated and developed. A serious attempt was made to capture both the hardening and softening of the sandstone rock. The effort started in the laboratory with a series of triaxial tests conducted for different confining pressure for 3 types of sandstone. A systematic approach has been used to analyses the rock mechanical data to pick proper yield, peak and residue strength, besides common elastic properties. A new constitutive model is then developed and validated. The new constitutive model (known as Assef-Surej-Ariffin, ASA model) is able to capture the full elasto-plastic rock mechanical behavior including softening and post failure which is critical for oil and gas applications such as sand production and drilling. An FEM code is used to validate the new constitutive model and the results compared with the modified Mohr Coulomb criteria. The results show that the new ASA constitutive model gives a better match for most of the laboratory tests compared to Mohr Coulomb especially for the softening part. The new ASA failure criteria is planned to be used in sand production analysis to estimate the sanding propensity and rates where the post failure analysis will be key to the results.
Optimization of Microsphere Injection by Balancing the Blocking and Migration Capacities in a Heterogeneous Carbonate Matrix
Authors: Cao Dongqing , Han Ming , Wang Jinxun , AlSofi Abdulkareem 
Published: November 2020

AbstractMicrosphere injection aiming at in-depth fluid diversion is based on the microsphere retention induced by the particle-rock/brine interaction in hydrodynamic environment. The retention generates steric blocking to the high permeability zones but retards the microsphere migration to the deep reservoir. This work studied the flow properties of microsphere samples in heterogeneous carbonate core plugs for an optimum blocking and migration capabilities. The oil production potentials of blocking-dominant and migrate-dominant microsphere samples were compared.Coreflooding tests were performed to evaluate the microsphere flow properties and oil production potential at 95°C and 3100 psi pore pressure. The carbonate core plugs with middle to high permeability were used. The flow property evaluation started with quantitative microsphere injection of eight pore volumes, followed by postwater injection. The injection pressures were recorded and produced microsphere concentrations were monitored. Oil displacement tests were conducted using selected microsphere candidates by 1 pore volume microsphere injection after waterflooding. Effects of microsphere sizes were investigated.The flow properties of eight microsphere samples with different particle sizes and aggregation properties were evaluated. Particle size was a dominant factor for the microsphere flow in the core plugs. Larger particles tended to retain in the pores rather than migrate forward, resulting in higher flow resistance with less breakthrough. Suspension in polymer solution improved the ability to penetrate deep into the formation. Microsphere with better coalescence stability in the brine showed better migration performance. Three microsphere samples with particle size at nano-, sub-micron and micron scale were selected to evaluate the oil production potential. One pore volume microsphere injection by the nano- and sub-micron microspheres after waterflooding increased oil production by 11% and 16%, respectively, which were much higher than the oil production by micron microsphere injection. A balance between effective blocking and deep migration was required to achieve optimal performance. The optimization process is developed for the microsphere injection in the field application.
Core-Independent Saturation Height Function from NMR Logs in Carbonates-A Must in Current Oil Price Environment
Authors: Nandi Anindya , Mondal Ilius , Jain Vikas , Vij Jitesh , Verma Ankit , Chaturvedi P. C. , Haldia B. S. 
Published: November 2020

Abstract
The present oil industry is more challenged than ever to develop novel methods for oil exploration and production, while reducing costs at the same time. This necessity changes the need of logging tools for reservoir characterization. Saturation height modeling (SHM) is an important aspect of determining the production capability of an oilfield. This is often performed by taking core samples, which is pivotal for such analysis, but expensive and challenging. Further, cores are usually taken in the zones of interests in the well. This calls for an alternate analysis, which is not only available for the entire interval of the well but is also less expensive than the traditional coring techniques.
Nuclear Magnetic Resonance (NMR) applications have proved promising over the years to perform SHM, without using cores. NMR, however, has a shallow depth of investigation and using wireline measurements is even more challenging due to longer time after bit and increased mud filtrate invasion. Consequently, its use is restricted to quantifying porosity. This makes it imperative to remove the effect of any filtrate or hydrocarbons from NMR logs to be able to use them for any advance analysis.
A novel methodology is presented in this paper to perform SHM analysis in carbonates. It uses NMR data along with modern processing techniques like factor analysis (Jain et al. 2013) and fluid substitution (Minh et al. 2016) and integrated workflow to define hydrocarbon uncontaminated pseudo capillary pressure curves and saturation height functions for different rock facies observed in the formation. The results are validated on five wells in the same field, and further confirmation is also done with testing results.
Kahmah Reservoir Conceptual Model in South Sultanate of Oman: A Case Study of Field Extension
Authors: Sabahi Atiya , Rahbi Said , Harthi Mahmood , Choudhury Suryyendu , Darmaki Faisal , Lawati Ali , Ghatrifi Suhaib , Mahrouqi Iman , Morianta Marpaung , Abri Yaqoob , Al-Jumah Ali 
Published: November 2020

Abstract
The objective of this study is to evaluate and de-risk the extension of the Kahmah Group, which is a newly identified carbonate extension in the Eastern part of XX field, and to assess and unlock further appraisal and development opportunities.
Eastern field correlation was done by correlating the wells that has encountered Kahmah carbonate, the ones showing low Gamma Ray (GR) traces. Well correlation was done mainly on Petrophysical properties of three vertical penetrations that show distinct and abrupt change from high GR (Base Nahr Umr Shale and/or Mahwis sandstones) to low GR reflecting Kahmah carbonates.
Based on the thicknesses of Kahmah based on the vertical well data and commercial oil seen in all wells in the vicinity, thickness and expected oil distribution maps were created.
The main findings from the correlation are: 1) Kahmah reservoir is divided into two pays and two non-pays zones as seen in XX-1H1. 2) The reservoir is thickest around XX-1 and thins out toward YY-10 to the south and disappears completely in XX-5 to the north, portraying a wedge- shape.
Kahmah reservoir varies in thickness, with thickest interval encountered in XX-1 with 11m. The reservoir thins out towards the edge closer to YY-10 confirming the wedge-like structure.
A conceptual understanding has been incorporated in generating cross-sections portraying and proving the wedge-shape structure of Kahmah.
Like any other new formation development, many uncertainties are associated with Kahmah development like formation extension, reservoir/fluid properties, pressure behaviour and others.
The key observations from this project can be summarized as following: Different packages of reservoir. May be of different or similar propertiesExtension of Kahmah towards northern part of XX field is still highly uncertainContinuity of Kahmah Reservoir is uncertainReservoir pressure and communication with Mahwis formation need to be evaluatedReservoir and fluid properties also need to be evaluated
Fracturing and Production Observations from the First Two Horizontal Wells for Shale Oil Exploration in Ordos Basin
Authors: Hou Yuting , Wu Yong , Hu Xifeng , Tang Meirong , Liu Yuan , Zhang Jie , Niu Li , Xu Wenran 
Published: November 2020

Abstract
The continental depositional environment poses unique challenges for the exploration of unconventional resources. The tight reservoir nature requires horizontal drilling and multistage completion. However, the geologic discontinuity and the geomechanical heterogeneity complicate lateral completion design, fracturing treatment execution, and production analysis. The experience of developing the first two horizontal wells for shale oil exploration in the Ordos basin resulted in observations that link the geology, reservoir, geomechanics, and production behaviors, which can be used for future appraisal and development in similar environments.
In 2014, one exploration well in the south Ordos basin demonstrated that the source rock from the Chang-7-3 formation could produce good light oil, but the tight reservoir needed horizontal drilling and multistage fracturing completion to achieve the production potential. In 2019, two horizontal wells were placed adjacent to each other for appraisal purposes. Due to the unique lacustrine deposition environment of the Chang-7-3 formation, landing the laterals in the target formation proved to be very challenging even with special geosteering tools. For both wells, the net-to-gross ratio is less than expected (51% and 38%), creating significant challenges for the ensuing completion phase. The multistage completion and fracturing were designed with full consideration of the horizontal lateral conditions. Reservoir quality (RQ), completion quality (CQ), and geology quality (GQ) were considered to optimize the completion staging strategy and fracturing plans. Besides the pressure response during fracturing, two additional monitoring and evaluation systems were deployed during the completion phase: microseismic interpretation and chemical tracers. Observations from these three measurements provided valuable information of how the formation responded to the staging strategy, fracturing initiation and diversion, and flowback and production.
Post-fracturing production from both wells met expectations in the testing phase. Additionally, the observations during fracturing and flowback of those two wells provide unique value for better understanding the Chang-7-3 formation. Fracture initiation proved to be feasible only in the lateral sections with proper sand facies where good RQ and CQ were found. Microseismic monitoring showed fracture orientation and planar extension in space. Tracer results revealed where the formation hydrocarbons came from and how the two wells interacted. This case study will have significant influence for future drilling and completion in the Chang-7-3 formation and provide a useful case history for continental shale oil scenarios.
Collapse Design of UOE-Pipe Wellbore Casing
Authors: Liu Zhengchun , Samuel Robello , Gonzales Adolfo , Kang Yongfeng 
Published: November 2020

Abstract
Recently, well design engineers attempted to replace traditional API 5CT pipes with cheaper UOE steel pipes in the downhole wellbore construction. The UOE method for producing longitudinally welded large-diameter pipes creates typically weaker pipes in terms of collapse resistance. The standard API 5C3 collapse design procedure no longer meets safety requirements. A practical solution to this issue is discussed.
UOE pipe casing can be designed based on the new collapse strength envelope, which is established by modifying the API RP1111 collapse strength model. The original API RP1111 collapse strength model was intended for pipeline design, not downhole tubular design. It is comprised of the elastic collapse term and yield collapse term, with the latter being proportional to material yield strength. However, the deration effects of temperature, tension, and internal pressure are not included. For downhole wellbore tubular design, yield strength is replaced with equivalent yield strength (from API 5C3 new addendum), which is a function of temperature, axial stress, and internal pressure.
A new casing design workflow has been implemented in the computer program, and case studies were performed to verify the collapse design results. A new collapse pressure envelope was generated using the computer program integrated with a commercial tubular design tool and was compared to the traditional API 5C3 collapse pressure envelope. As expected, the new collapse strength values, calculated using the modified API RP1111 collapse model, are typically much lower than the estimated values using the API 5C3 collapse formula.
Results of the collapse safety factor and maximum allowable wear are also compared between the modified API RP1111 collapse model and the traditional API 5C3 collapse model. Typically, UOE pipe using the modified API RP1111 collapse model generates lower safety factor and maximum allowable wear values, as expected.
The API RP1111 collapse strength model has been modified to include the deration effects of downhole conditions. Implementing this model in the commercial tubular design tool enables the cost-effective design of wellbore casing strings using cheaper UOE-manufactured steel pipes.
A Novel Characterization and Evaluation Method of Flow Field and its Application
Authors: Qiao Yan , Yang Xiangtong , Zhang Yang , Wang Yonghong , Hou Tengfei , Huang Bo , Shang Litao , Li Huili 
Published: November 2020

Abstract
At present, most of the oil fields in eastern China have entered the stage of high water cut development, with a comprehensive water cut of over 90% and an oil recovery of less than 30%. To improve oil recovery, the flow field must be described qualitatively and quantitatively, so as to provide a basis for the formulation of measures. This paper proposes two categories of indicators: one is a guideline for developing measures, including streamline bundle properties, and the other is an indicator for evaluating the effects of measures, remaining oil dispersion (ROD) and dynamic heterogeneity included. Through numerical simulation methods, the regularity research and adaptive evaluation of each flow field characterization indicator are carried out. Finally, according to the streamline bundle properties of block E, the liquid rate of injection and production wells were optimized, and the effectiveness of the optimization was evaluated. The study found that under the condition of fixed well pattern, the streamline bundle flow (SF) between wells is relatively stable, and the change in streamline bundle potential (SP) and streamline bundle oil cut (SOC) tends to decrease with time. The typical curve of ROD generally includes four stages, and the effectiveness of measures is judged by the trend of ROD. For dynamic heterogeneity, the change curve generally includes unstable stage and stable stage. The value of the stable stage value can reflect the heterogeneity of the flow field. The larger the value, the stronger the heterogeneity of the flow field. According to the streamline bundle properties, three liquid rate optimization strategies, which are streamline bundle flow method (SFM), streamline bundle potential method (SPM), and streamline bundle oil cut method (SOM), are proposed, and the effectiveness of the measures is evaluated using ROD and dynamic heterogeneity. After liquid rate optimization, the ROD of the reservoir in Block E increased and decreased later, the Lorentz coefficient decreased, and the recovery increased by 3.76 percentage points. It provides a new technical means for the adjustment and evaluation of the flow field in the later stage of high water cut oilfield development.
Integrated Reservoir Characterization and Completions Design Using Petrophysical and Acoustics Logs in Unconventional Tight Formation
Authors: Das Ritwika , Chatterjee Chandreyi , Jain Vikas , Majumdar Chandan , Hussain Syed Aaquib 
Published: November 2020

Abstract
With all the conventional reservoirs being almost exhausted around the world, our immense dependency on unconventional reservoirs has led us to look for measurements that are beyond conventional way. In the optimal exploitation of unconventional reservoirs, integrated Petrophysical and Geomechanical studies provide the best means to both 1) evaluate formation properties such as fluid types, volumes and flow potential, and 2) use this information along with rock's mechanical properties to optimize completions program and maximize production. While a basic petrophysical study can be made using triple combo logs gamma ray, neutron porosity, density and resistivity - for reconnaissance and quick look, such studies are not enough for the purpose of completions and production optimization in unconventional. A combined study using different petrophysical, geological and acoustic logs is used in order to answer the questions and problems faced during characterizing a tight unconventional reservoir. The answer products from these will help in advanced studies which would include reservoir characterization and completion design.
For that, we would need to bring in acoustic measurements to determine rock types and respective mechanical properties, which would be influenced by fracture, anisotropy, stress direction and permeability of the formation. Spectroscopy logs will further add to knowledge of the lithology at mineral level, required for petrophysical evaluation and rock physics modeling. Today advanced spectroscopy logs also measure Total Organic Carbon (TOC) percentage of the formation, important to understand source rock maturity and to determine true flow potential in tight formations. Images from Micro Imaging resistivity tool are important in unconventional to evaluate fractures which often times are the only source of permeability in tight rocks. Nuclear Magnetic Resonance is considered essential to determine fluid types, respective volumes and bulk permeability of unconventional formations. An integrated study using all the above measurements helps best combine Petrophysical and Geomechanical aspects of the formation under investigation. Furthermore, in unconventional reservoir evaluation, such a study helps us to determine stress barriers to hydraulic fracturing important to zone-wise design and optimize completions program.
In this paper, we present a systematic procedure and corresponding results of an Integrated Petrophysics and Geomechanics study in an unconventional tight reservoir, which helped to 1) optimize hydraulic fracturing and completions program, and 2) create complete model of hydrocarbon production.