bluuebunny/crossref_metadata_2025_split huggingface dataset:
Derivation of New Analytical Expressions for Calculation of Gas-Liquid Relative Permeabilities through Fractures-Part I: Incompressible Flow
Authors: Saboorian-Jooybari Hadi , Abeyat Ehsan 
Published: October 2015

Abstract
The problem of multiphase flow through underground geological fractured formations arises in various areas of geosciences such as geology, hydrology, petroleum, soil, and environmental engineering. Considering the fact that flow in fractured formations is fracture dominated, relative permeabilities through fractures must be well understood. The comprehensive literature review of this paper shows that few experimental, numerical, and analytical studies have been performed to describe two- and multiphase flow in fractures. Contrary to reservoir rocks, there is no standard experimental procedure for measurement of relative permeabilities through fractures. Furthermore, existing techniques are generally inconsistent, time consuming, expensive, complicated, and may fail due to technical difficulties encountered while performing the experiments. Thus, developing an analytical model for accurate prediction of relative permeabilities through fractures is of vital importance for treating one of significant uncertainties associated with characterization and simulation of fractured reservoirs.
Historically, the straight-line relative permeability model (X-curve) has been widely used in numerical simulation of fractured reservoirs. However, experimental measurements of gas-liquid relative permeabilities through fractures have revealed high degrees of phase interference which cannot be well represented by the X-model. In this work, idealized flow configurations of stratified and segregated flow are assumed in order to make the analytical derivation tractable without the need of using numerical techniques. Then, basic fluid flow equations are combined to develop simple analytical models for gas-liquid flow in each of the patterns. Combining the models with Darcy's law leads to closed-form analytical expressions for explicit calculation of gas and liquid relative permeabilities through fractures. The relationships simply state that the relative permeabilities depend on several parameters one of which being the saturation, whereas they were considered to be only functions of the saturation in the classic X-model. Afterwards, the formulas are further simplified by adopting a realistic assumption. Eventually, the validity of the derived relative permeability expressions is checked by comparing their predictions with available experimental data. The results show that the ability of the segregated model to accurately predict experimental data is considerably poorer than that of the stratified model. Therefore, the generalized relative permeability expressions proposed for the stratified pattern must be used to describe the dynamics of gas-liquid flow in fractures. It addition to robustness, other advantages of the newly presented formulas such as simplicity, cost effectiveness, and being explicit and analytic make their implementation in numerical simulators straightforward.
Hybrid Solution Improves ROP and Borehole Quality in Challenging Large Diameter Holes
Authors: Omar Marwa , Valbuena Franklin , Abdelhamid Atef , Agawani Waleed , Taha Mohammed , Saleh Khaled , Baqer Yousef , Nath Saswata , Abbas Moufid 
Published: October 2015

Abstract
In the prolific Burgan field, South East Kuwait, new well profiles are being employed which require the 16 inch hole section to be drilled deeper. This new well profile requires drilling through interbedded abrasive sandstones and sticky shale which were previously drilled in 12 ¼ inch hole size. Drilling becomes increasingly challenging using larger diameter bits where torque fluctuations, down-hole conditions and durability limit performance. As the casing profiles changed, each section's drilling solution was revisited as drilling dynamics and performance diminished drastically when drilled in the larger hole size. What was once a viable solution to drill the section in 12 ¼ inch becomes no longer suitable when drilled in 16 inch. The purpose of this paper is to demonstrate the engineering analysis for large diameter hole application and the selection of an optimized hybrid drill bit design, roller cone combined with Polycrystalline Diamond Compact (PDC), to maximize drilling performance where standard PDC or roller cone bits alone fail to provide an optimal solution.
The 12 ¼ inch section was typically drilled using a rotary bottom hole assembly with a roller cone bit or using a performance mud motor with a PDC bit. Drilling parameters were reduced in the upper layers especially with PDC bits as they involve sticky shale which can induce bit balling. While in the lower layers the abrasive formations tend to wear down roller cone bits.
Combining the benefits of both bit types, a 16 inch hybrid bit was proposed to answer the challenge of drilling the section as fast as a PDC bit while providing the stability, torque control and smooth hole condition generated by a roller cone. Selecting an appropriate hybrid design to match the application resulted in an initial trial of a durable hybrid bit that finished the interval with virtually no wear on the bit and significantly improved borehole quality. The second trial of the hybrid bit with a modified, more aggressive design approximately doubled the ROP of a PDC bit while maintaining a smooth hole profile and minimizing torque.
PDC bits generally provide faster rate of penetration than roller cone bits while generating higher torque fluctuations as they drill by shearing bottom hole formation. Due to their high torque demands, PDC bits require an additional mud motor to drive them efficiently in larger hole sizes. Roller cones crush and gouge the bottom hole formation and due to their mechanical rollers result in reduced reactive torque and a smoother hole profile. Hybrid drill bit technology proven the capability of achieving the benefits of both designs in specific selected applications.
The Implementation Phase: Improve the Intelligent Field Real-Time Data Reliability Using Key Performance Indices
Authors: Al-Amer Abdulrahman A. , Al-Naser Naser , Al-Kadem Mohammad S. , Abo Khamseen Mohannad A. 
Published: October 2015

Abstract
Nowadays, there is a massive amount of real time data that flows from the intelligent sensors to the petroleum engineers desktop. High quality data is required to utilize in production workflows and technical studies. The reliable transmitted data as real-time pressure and temperature will enable the petroleum engineer to track the performance of the wells, generate production strategies, and monitor the real-time production, and a lot of more workflows remotely from his/her desktop without jeopardizing the well condition or the reservoir structure.
In Saudi Aramco, monitoring the quality of real-time data for validity, accuracy, consistency and intelligent field equipment integrity is accomplished via the utilization of state-of-art intelligent field data health monitoring platform. It provides an alarming system of problematic data and equipment. It also generates a daily data quality report for a specific intelligent field data transmission node.
This paper is a continuation of the technical paper titled "Intelligent Field Real-Time Data Reliability Key Performance Indices" (IPTC-17997-MS, Kuala Lumpur, Malaysia, 10-12 December 2014). This paper will highlight the tangible benefits of implementing the new monitoring platform in four different examples that show the importance of having intelligent field data reliability tracking solution in each oil and gas company to improve the data reliability. Making the decision process accurate, through utilizing an advanced automated data management platform, is crucial butreceiving real-time quality data is essential.
Identification and Characterization of High-permeability Zones in Waterflooding Reservoirs With an Ensemble of Methodologies
Authors: Ding Shuaiwei , Jiang Hanqiao , Wang Lei , Liu Guangwei , Li Ning , Liang Bin 
Published: October 2015

Abstract
Efficient management of water flooding oil fields requires an accurate characterization of high-permeability zone, which evolves from long-term water flooding, as sand production and clay erosion have contributed to the variation of formation structure. These zones are a subject of concern for reservoir engineers, as they lead to early water breakthrough in oil producers and uneven sweep around water injectors. The objection here is to use an ensemble of methodologies to determine the level and characterize high-permeability zones in waterflooding reservoirs.
X oilfield in western North China has entered into a high-water-cut stage and high-permeability zones are increasing serious with the development of the oilfield. All the parameters are obtained from reservoir numerical simulation model after automatic history matching (AHM) using ensemble Kalman filter (EnKF) with covariance localization. The updated reservoir model is used to characterize the high-permeability zones in the reservoir. Then, theory of logical analysis (TLA) is used to select the static and dynamic parameters which are most correlated with the formation of high-permeability zone, for there are many variables involved in the evaluation on determining high-permeability zone. Extensive laboratory testing and dynamic analysis prove that wells that tend to form high-permeability zone have certain similarities on geological structure and dynamic performance, thus the reservoir can be graded into three types of absence of high-permeability zone, presence of light high-permeability zone and presence of large high-permeability zone according to fuzzy C-mean clustering algorithm (FCMCA). This results were verified by a typical well group through interwell tracer and historical water injection profile. This methodology is also useful for the design of water shutoff and profile control by polymer injection at the high water-cut stage of the oil field.
Case Study of Fine Geological Modeling for Mishrif Carbonate Reservoir of H Oilfield in Iraq
Authors: Limin Zhao , Duan Tianxiang , Han Haiying , Xu Jiacheng , Guo Rui , Zhu Xiang , Liu Lei 
Published: October 2015

Abstract
Accurate geological characterization for complex carbonate reservoirs plays an important role in guiding the optimal oilfield development. Mishrif Formation of H Oilfield in south of Iraq is the most important target among several Cretaceous oil-bearing carbonate formations due to the high OOIP proportion. It is composed mainly of bioclastic limestone with multiple pore types. It is massive reservoir with medium porosity and low permeability. The great variation of vertical and lateral reservoir quality leads to poor relationship between porosity and permeability which brings great challenge in reservoir characterization and favorable area identification. This paper presents the comprehensive reservoir evaluation and characterization in combination of all data available. The sedimentology and stratigraphy are reviewed in terms of depositional environment and lateral stratigraphic correlation. The variability inherent to the depositional mode and digenesis leads to complex reservoir geometry and pore types. Rock typing is examined based on core measurements and well logs to get the improved correlation coefficient between porosity and permeability. Neutral network method is used to propagate the rock types to un-cored wells to get the accurate permeability estimation. Facies model and rock type model are built constrained by the seismic inversion reservoir prediction results which provide crucial information on carbonate proportions distribution, especially in areas with low well control. Permeability model is generated constrained by rock type and porosity which can indicate the reservoir flow capacity. Based on the integrated reservoir model, horizontal wells and multilateral wells for Mishrif Formation are proposed and optimized in the good reservoir quality area. The high individual well production rate verified that the well placements upon fine reservoir modeling are successful.
Lessons Learned From a Subsurface, Well Completion, and Hydraulic Fracturing Perspective for a Multiwell Liquid-Rich Resource Play in West China
Authors: Zhang Jing , Jiangwen Xu , Liu Yuan , Judd Tobias , Liu Hai , Li Niu 
Published: October 2015

Abstract
There is a variety of well completion and hydraulic fracturing technologies available for liquid-rich resource plays. The industry approach tends to include horizontal wells with multiple fracturing treatments, and depending on the selection criteria, it may result in certain operational efficiency and production enhancement advantages. Thus a comprehensive strategy to properly select the applicable technologies is based upon geology, subsurface understanding, well design, production expectations, and operational readiness.
Following the successful completion of the exploration phase of the Jimusaer project located in the Jungger Basin of West China, a pilot drilling program was initiated that included multiple horizontal wells being drilled from selected well pads. The completion and fracturing operations were completed in two phases that included the evaluation of different completion technologies, placement methodologies, and fracturing designs being optimized for later wells based on initial well results. The initial phase was done in 2013 and included 62 fracturing stages on four wells completed with an openhole sliding sleeve system. The six remaining wells were completed in the following year which involved 130 stages. Besides optimizing the fracturing design approach, it included a shift towards cased-hole completion techniques involving the plug & perf approach.
Overall technical understanding and recognition of underlying trends were improved by reviewing the abundance of reservoir and well data from the 10 horizontal wells completed to date. Additional insight was obtained by the incorporation of hydraulic fracturing monitoring measurements with flowback performance and monitoring of individual fracturing stages through the deployment of unique chemical tracers. Despite the variation in completion and fracturing technology, reservoir understanding and well placement were the primary factors impacting individual well performance. In conclusion, the overall pilot project was designed to reduce the uncertainty in key reservoir parameters, test various completion/drilling technologies, and assess full-field development issues while moving towards fairway sweet spots.
Offshore Coiled Tubing Interventions Maximized the Value of Watered Out Mature Fields Using Selective Water Shutoff Treatments With an Organic Crosslinked Polymer in a High Temperature Sour Well
Authors: Beltagy Ahmed El , Taha Islam , Shawky Ahmed , Gaber Nabil Salah , Elwan Mahmoud Attia 
Published: October 2015

Abstract
Saqqara is a very challenging field in the Gulf of Suez in the Red Sea area, producing from the deep sandstone Jurassic formation. This formation can sometimes be watered out, with a combination of high H2S and CO2 levels in the production. High sand quality has developed high horizontal and vertical permeability, which challenges any water shutoff treatment placement.
One of the critical measures of success in water shutoff treatments is selective zonal shutoff across an existing hydrocarbon zone. It was challenging to select a deep penetration polymer to treat the selected zones, as it must resist high temperature degradation (321°F), particularly in existence of high concentrations of H2S. Different water shutoff (WSO) treatments were considered, but selecting an organic crosslinked polymer (OCP) gave the best lab results because of its stability in high temperature conditions.
Placement and isolation techniques were challenging, particularly with the existence of multiple zones of interest. Therefore, coiled tubing (CT) well intervention methods were selected for best placement without resorting to a more expensive workover option.
The results of the treatment were designed toward the sustainable production of these kinds of mature watered out fields. The treatment succeeded by reducing produced water from almost 2,300 BWPD down to almost zero BWPD.
This process allows the operator to increase the drawdown value, which strongly affects the BOPD value compared to the initial watered-out condition. The treatment maximized the value from mature fields revitalization, redevelopment, and end of field life planning.
Efficient Sampling Scheme for Uncertainty Quantification Using PCA
Authors: Kang B. , Lee K. , Choe J. 
Published: October 2015

Abstract
Reliable uncertainty quantification requires a large number of simulation models and huge computation time. It would be preferable for simulation time to be short to apply in real field management. Therefore, our aim is to reduce the total simulation time as well as predict future reservoir performances reliably. In this study, we propose a novel method to sample ensembles using principal component analysis (PCA) and K-means clustering.
We construct a two-dimensional plane on which initial ensembles are projected with their principal characteristics. The plane is made by eigenvectors of the data corresponding to the largest eigenvalues. Divided into 10 groups using K-means clustering, we choose the same number of ensembles from each group. Clustering helps to sample unbiased ensembles. It can be a biased sampling without the clustering procedure.
We compare uncertainty ranges using 100, 50, and 20 sampled ensembles with those of initially generated 400 ensembles. Compared to the non-sampling case, the results with the proposed method show comparable quality in predicting oil and water productions on a synthetic reservoir. Uncertainty ranges with the sampled ensembles have similar trends with the base case and 100 ensembles show an optimal results, considering both prediction quality and total simulation time. We reduce 94.8% the total computation time at maximum as well as maintaining uncertainty ranges from the 400 ensembles. The proposed sampling method takes only few seconds so that it suggests powerful applications for efficient history matching and helps fast and reliable decision making.
Inflow Performance Relationship correlation of 2 Phase CBM Reservoir
Authors: Sugiarto Isan , Mazumder Saikat , Wittemeier Roxanne , Sharma Vikram 
Published: October 2015

Abstract
The inflow performance relationship (IPR) for a coalbed methane (CBM) reservoir is relatively complex as the production behaviour is different from conventional gas wells, as gas in coal is stored by means of adsorption. Most often coal reservoirs are relatively under saturated, meaning the pressure in the reservoir needs to be substantially depleted prior to gas desorption. Gas from coal is produced at relatively low reservoir pressures, thus requiring the pseudo pressure function to be included in any deliverability calculations. A two phase flow system in a coal reservoir adds to that complexity as relative permeability, reservoir geo-mechanics and saturation needs to be taken into account within the IPR correlation. The IPR correlation for coalbed methane wells is an important part of any well performance optimisation and nodal analysis.
A simplistic IPR correlation for multi-phase coalbed methane wells was generated based on the history matching of field production data. The correlation has been tested both for a multi seam completion in the Surat Basin and for horizontal wells in low permeability coals within the Bowen Basin. Furthermore the empirical CBM IPR correlation for single and multi-phase reservoir was compared. A sorption isotherm was used to limit the maximum recovery and generate recovery efficiency based on the IPR correlation.
One of the potential risks to a CBM development is the likely loss in recovery efficiency due to higher backpressures on wells as a result of suboptimal gathering network sizing due to a chosen surface concept. This risk needed to be further evaluated and addressed for potential outcomes when the field starts production. The study was initiated by means of using the CBM field IPR's to evaluate this risk in more detail, identify mitigation measures and capture any associated opportunities that may be available.
New Solutions for High-Pressure and Salt/Anhydrite Rocks Casing Cementing, A Case Study
Authors: Zhen Nie , He Liu , Zou Jianlong , Xu Daiwen , Zhang Zhenyou , Chen Yufeng 
Published: October 2015

Abstract
High-pressure and salt /anhydrite rocks at 1340-1950m Lower Fars formation present a lot of challenges in 244.5mm casing cementing in Halfaya oilfield due to existing the alternations of salt and anhydrite and clay, high pressure, high salinity(160000~220000ppm), low static temperature (30-70°C) and narrow safety margins (0.08g/cm3), which all contribute to not only limit the achievement of high performance high density salt resistance slurry, but also lead to the low pump rates and bad displacement rates due to the only 0.03 g/cm3 density difference between the drilling fluids with density of 2.25 g/cm3 and the cement slurries with density of 2.28 g/cm3 during cementing operation, and long cementing job duration caused by the constraints of large annular clearance and long isolation interval, so poor slurry performance, severe lost circulation, hole instability and well kick is likely to occur simultaneously during drilling and cementing process, all result in unsuccessful cementing job and poor cement bond quality. In some cases, right after the wells were put on production, the 9 5/8" casing annulus would show an increase in casing head pressure. So a new high efficiency sealing spacer with density of 2.20 g/cm3 was developed to displace drilling fluids effectively, which is composed of weighting agent, suspending agent, dispersing agent, fluid loss agent and anti-leakage agent. At the same time, a new high performance salt resistance slurry system with density of 2.28-2.30g/cm3 has achieved with good stability, proper rheology, and high early strength development of set cement. the 10-15% optimal salt concentration (BWOW) has obtained by the evaluation of rheological property, fluid loss control ability, thickening time property and ultrasonic compressive strength development under the different salt concentration(0~30%); the optimal weighting agent component ratio ((ilmenite: Manganese powder =4:1) and dosage (83%) is determined by building mathematical model to calculate the packing density(φ) of the dry blend with different proportion and water demand, and evaluate slurry properties, introduce a new Carboxylic acid salt salt-resistance dispersant to maintain the good rheological properties. This new slurry technology not only simplify cementing job from the two-stage to one-stage but also improved the cementing bond quality and reduce costs. Extensive lab experiments and pilot tests prior to field application demonstrated the superior performance of this sealing spacer and new salt resistance slurry system; more than 45 wells onsite cementing jobs have been completed in the field with great success. This paper will systematically describe the details of lab development of high density salt resistance slurry system and present case histories to demonstrate its effectiveness in high-pressure and salt /anhydrite rocks casing cementing.