bluuebunny/crossref_metadata_2025_split huggingface dataset:
What We Learned from a Study of Re-fracturing in Barnett Shale: An Investigation of Completion/Fracturing, and Production of Re-fractured Wells
Authors: Wang Sharon Yunhong , Luo Xin Lucy , Hurt Robert Samuel 
Published: May 2016

Abstract
The success of the Barnett shale helped to revitalize the oil and gas industry in the United States, and sparked a wave of shale development programs. At the same time, it has caused practitioners to rethink how, or even if, we can apply certain theories and technologies developed and implemented in conventional reservoirs to unconventional reservoirs. One fundamental difference in unconventional reservoirs is several orders of magnitude lower rock matrix permeability, largely requiring stimulation for economic development.
Re-completion/fracturing in shale reservoirs is a means to increase production by accessing reserves beyond the volume achieved from initial completions. Re-fracturing may also be applied to wells with inefficient initial completions, less-than-optimum designs or executions, and in depleted wells in which it is possible to treat previously un-stimulated rock volume.
We performed this study to discover how production is impacted by recompletion and re-fracturing. By studying specific treatment and production data sets in the Barnett, we searched for new insights about how shale plays should be developed. In this work, we extracted about 200 re-fractured or re-completed wells with treatment information and production data in the Barnett Shale play from a service company&apos;s database and a public well database. In this analysis, we took into account treatment data in both initial and refracturing, and evaluated their impact on long-term recovery. Further, we considered other available data in this investigation.
In order to identify hidden, potentially predictive information in the data set, exploratory data analysis, univariate and multivariate/ cluster analysis techniques were applied using statistical analysis software such as SAS, combined with Geographic Information System (GIS) software.
The paper is organized mainly in two parts. The first part is a data mining study on production and treatment data to discover certain treatment parameters controlling production for both initial completion and refracturing; in the second part, we interpret those observation and findings from perspective of mechanism.

Introduction
In the Barnett, large-volume water fracs are a successful completion method that has resulted in superior production. The practice, when used previously in other shale reservoirs, did not generate the same magnitude of success as observed in the Barnett. Every shale reservoir is unique; however, the fundamental mechanisms that enable successful water fracturing in the Barnett likely apply to other reservoirs. Unfortunately, it seems much of the literature have not addressed fundamentals clearly.
Application of Advanced Mud Gas Logging for Improved Hydrocarbon Phase Determination in a Highly Depleted Reservoir
Authors: Crampin Tom , Gligorijevic Aleksandar , Clarke Ed , Burgess Jamie , Chung Shao-Jung 
Published: May 2016

Abstract
Downhole determination of hydrocarbon phase is a significant subsurface challenge in many highly depleted fields. Reservoir production results in fluid compositional changes and variable hydrocarbon saturation distributions. Standard petrophysical techniques such as analysis of density and neutron porosity logs can give misleading results under such conditions. Most commonly, oil reservoirs can display a neutron-density response indicative of gas. There is significant business impact in error of hydrocarbon phase determination. Mistakes can lead to poor completion decisions, incorrect reserves estimation and suboptimal well and reservoir management.
The fluid phase uncertainty resulting from interpretation of standard Logging While Drilling (LWD) datasets can be unacceptably high. Additional tools or techniques are therefore required. Downhole fluid sampling is one such technique. It is routinely and successfully acquired in exploration and appraisal wells and gives robust fluid phase determination. However, it is not economically feasible for frequent acquisition for in-fill production wells where low cost LWD acquisition is the norm. In addition, overbalanced wells drilled through highly depleted reservoirs lead to acquisition risk in stationary openhole logging techniques. Advanced Mud Gas logging (AMG) is an established tool for delivering real-time quantitative fluid composition in exploration, appraisal and early production wells. However, successful applications in highly depleted fields have not been published as AMG analysis can be complicated by compositional changes. In this paper we present a case study calibration of AMG with downhole fluid samples resulting in a robust, cost effective and safe tool for improved hydrocarbon phase determination in depleted reservoirs.

Introduction
Many techniques are used to determine hydrocarbon phase but all of them can be impacted by production related changes to reservoir fluids. The neutron-density "cross-over" is the most common gas identification tool (Figure 1). It results from an anomalously low neutron porosity reading in gas, due to low hydrogen index (HI), and an anomalously high density porosity reading, due to low fluid density. A second traditional technique is the neutron near count to far count ratio. The near detector reads largely in the near wellbore invaded zone where high mud filtrate saturation results in a high HI and a relatively low count rate when overlain with the far detector, which reads deeper into the formation, past the invaded zone, resulting in a relatively high count rate if gas is present.
Continental Carbonates as Hydrocarbon Reservoir, an Analogue Case Study from The Travertine of Saturnia, Italy
Authors: Ronchi Paola , Cruciani Francesco , Cirilli Simonetta 
Published: May 2016

Abstract
The Pleistocene Saturnia travertine represents an analogue of the pre-salt continental carbonate reservoir discovered on both sides of the South Atlantic margin. Two sub-horizontal travertine plates, few tens of metres thick and extended over an area of several kmsq, have been studied in 3D quarries exposures. The aim of this study was to reconstruct the facies variations and associate petrophysical properties applying an integrated multidisciplinary approach. The Saturnia travertine complex, due to warm waters spring still active in the area, is made of various stacked banks, separated by emersion erosive phases, showing alternation of lacustrine tabular bodies, terraces and sills. The facies association includes crystalline crust, pisoid, paper-thin raft, coated bubble, reed, lithoclast-breccia, micritic travertine. The d13C, ranging between +4‰ e +8‰, supports the CO2 volcanic mantel source, while the d18O from -5‰ and -9‰ is in agreement with warm meteoric water as for other travertine in the area. The Sr ratio isotopic signature is agreement with the carbonate derived from dissolution of Mesozoic deep seated carbonate. The facies reservoir properties have been studied through an integrated approach that includes porosity and permeability analysis on plugs, 3D X-Ray Computer Tomography, which evidenced the porosity connectivity, and image analysis on micro scale under thin section (microporosity) and macroscale on large rock slabs to define various porosity indexes (shape, roundness, pore size). A strong heterogeneity of the pore system and variable connectivity were pointed out. The porosity ranges from 4 to 30% and permeability is highly variable reaching hundreds of mD. The average pore diameter is between 1 and 4 mm, microporosity is low and the prevailing pore type is the inter-granular one. The study highlighted also that in travertine, the investigation should be conducted at a large scale in order to measure the large pores and wide scale connectivity.
Towards Improved Management, Interpretation and Integration of Dipmeter and Borehole Image Data
Authors: van den Heuvel Erik-Willem , Tengah Halimah , Goodall Tim , Pantic Dinah , Bal Adri 
Published: May 2016

Abstract
Historically in our industry, dipmeter and image log data, have generally bypassed the data management processes necessary to safeguard these data for future use. Brunei Shell Petroleum (BSP) is no exception to this, as concluded from a review of these data in 2011. BSP is perhaps one of the few E&P companies that has a significant amount of dipmeter and image data, more than 500 wells, exceeding 7000km, backdating to the early days of dipmeter tools, covering a wide range of historical recording mechanisms, computing platforms and principal databases. The current reality is that both raw and processed data are generally not readily available in a format usable by either petrophysicists or geologists. This is largely due to dipmeter and image tools having suffered a lag-time between tool evolution and effective data storage and archiving systems. As a consequence the potential value of the dipmeter and image logs has remained unrealized.
In 2012 BSP embarked on a Borehole Image (BHI) pilot improvement project consisting of some 54 wells, covering a wide range of dipmeter and image tools, with the objective to define data management standards and interpretation workflows aimed at effectively rescuing and ultimately ensuring full integration of this data. Integral to these improvements are recent advances in software capability to handle dipmeter and image log data. Our system and procedures allows for initial data QC and saving a "ready-for-interpretation" data subset available from our corporate data store.
Petrophysicists and geologists, who might not have the expertise to QC raw image log curves (maybe up to 30 curves types), now have the confidence to import and use the ready-for-interpretation dataset into Techlog. Legacy image logs are readily available for multi-well studies, reservoir correlation, structural ties to seismic, net-pay calculations over thin bed heterolithic intervals and facies logs for reservoir characterization.
Gas Drilling Wellbore Stability Analysis in Igneous Rock Carboniferous System of Dzungaria Basin
Authors: Wang Zonggang , Zhao Hongshan , Feng Guangtong , Han Laiju 
Published: May 2016

Abstract
During drilling operation in carboniferous system of Dzungaria basin, igneous rock was met, which leads to a low penetration rate and long drilling cycle, because of large thickness, high hardness and poor drillability of the igneous rock. Quasi-three axis confining pressure experiment was carried out with the igneous rock core of WUCAN 1 well. Experimental results showed that the igneous rock keeps a brittle fracture even in the confining compression pressure of 40MPa. Based on Mohr-Coulomb failure criterion, one analysis method about the applicability of gas drilling was put forward through comparing maximum principal stress while wellbore instability happened with upper-cover pressure. It can be concluded that gas drilling technology can be applied in carboniferous igneous strata of Dzungaria basin, when embedding depth is less than 6110 meters, which provides theoretical basis on the application of gas drilling technology in deep exploratory wells whose target zone is in igneous strata of carboniferous system of Dzungaria basin.

Introduction
After the discovery of SHIXI oil field and DIXI oil field in recent years, in the western new area of SLOF, SINOPEC, strata of carboniferous system are considered to be high potential. So several deep exploratory wells are mapped out by SINOPEC, including WUCAN 1 well. However, from current data, stratum of carboniferous system is mainly igneous rock, which has large thickness, high hardness and poor drillability. It leads a low mechanical drilling speed and a long drilling cycle. For WUCAN 1 well in the northern part of Dzungaria basin, conventional slurry drilling method is applied from well depth 4286 meters to 6323.6 meters. Many new technology solutions were successively used to enhance the drilling speed, such as ‘high efficiency roller bit + screw rod’ composite drilling, ‘Diamond head pregnant bit + high speed screw rod’ composite drilling, high frequency torsion impact drilling tools, waterpower impulse injector + high efficiency drilling bit of Baker Hughes. The results aren't pleased: average drilling speed is only 0.72m/h, and the drilling cycle is 239 days, which is more than half of the whole well cycle.
In the same stratum, compared to conventional slurry drilling technology, drilling speed and bit life can be highly increased by gas drilling technology [1–4]. So the application of gas drilling technology in igneous rock of carboniferous system in Dzungaria basin can be a possible way to overcome the bottle neck of drilling speed. Field engineering application shows that borehole stability is the main problem in gas drilling technology[5–7]. In this paper, mechanical properties of the rock nearby well wall are experimental investigated by quasi-three axis compression test, to evaluate gas drilling technology applicability in the igneous stratum of carboniferous system in northern Dzungaria basin.
Effect of Barriers on the SAGD Performance Result
Authors: Zhou You , Xi Changfeng , Wu Jian 
Published: May 2016

Abstract
The barriers in oil reservoir have great effect on SAGD production. Due to wide existence of interlayers, steam chamber can not move upward freely in perspective of chamber development, and also leads to a longer SAGD production cycle so as to increase the investment risk. Firstly the author studied the distribution and formation reasons of muddy barriers in the Zhong 32 of Windy City oilfield. Steam chamber developing characteristics and steam breakthrough pattern are studied by temperature detection data, historical data and microseismic data fitting dynamic data binding static geologic data. Barriers have three relative position relation with SAGD horizontal well. The order sorted by barrier influence to production from high to low degree: injection well inside barriers, between injection and production wells, above injection well. The results showed that the barrier pattern of Zhong32 is physical barriers, with characteristics of high shale-sand ration, low permeability, poor blocking ability. The horizontal continuous barriers increased steam channeling risks thereby control vapor liquid interface more difficult. Double tubes steam injection and artificial lift can be beneficial for the stable steam chamber operation, increase oil production and decrease water cut. High pressure steam operation increases the opportunities of barriers breakthrough by steam and obtains high oil production per day. The pattern of steam breakthrough in muddy barriers can be divided into bypassing and traversing.
Discussion on Unconventional Petroleum Reserves Classification and Evaluation in China
Authors: Bi Hai Bing , Wang Yong Xiang , Wu Guo Gan , Zhang Junfeng , Duan Xiao Wen , Sun Guang Bai 
Published: May 2016

Preface
E&P of unconventional oil and gas becoming wider and wider, reserves classification and evaluation methods of unconventional oil and gas resources are discussed and improved further, which has become the focus of related international conferences in recent years.
In China, based on the requirement of CBM development, relevant rules of reserves classification or calculation have been formulated at enterprise and industry levels in recent years.
But in general, these rules are just the continuation of traditional reserves classification system which mainly focuses on the OGIP classification and evaluation, and considers less on unconventional oil and gas characteristics (such as geological features, particularity of developing techniques and marginal economy, etc).
Furthermore, conflicts between reserves and mining right management are becoming prominentgradually, which affects the E&P of unconventional oil and gas in China to some extent.
A Novel Approach to Water-cut Prediction in Deep Cambro-Ordovician Tight reservoir with Complex Hydrocarbon Charge, Diagenetic and Structural Growth Histories
Authors: Mohsin Labib , Al Busaidi Salam , Aljiroudi Fadi , Al Lawati Mohammed 
Published: May 2016

Abstract
In deep tight shaly-sand reservoir, with complex hydrocarbon charge and structural growth history, it is difficult to characterize reservoir zones with high water cut from others with low water cuts and high hydrocarbon production rate, due to high resistivity readings of tight reservoirs.
Deep reservoir "B" in Abu Butabul Field, NW Oman has been charged via two genetically and chronologically different hydrocarbon phases (oil then gas); during a complex deep burial digenesis and structural trap history. Due to the variation of Hydrocarbon properties of such tight reservoir, it has been difficult to analysis such a reservoir using conventional petrophysical evaluation methods.
In this study, a modified version of the approach published by Ibrahim, Abd_Elmoula, Said Hasani, Sultan, Jahwari in SPE 130261 in which Ro (Resistivity of Rock saturated with Formation water) and SWirr (irreducible water saturation) used to distinguish water from hydrocarbon zones has been taken a step further in order to predict water cut in tight reservoirs (illustrated in the workflow below).
After calculating wireline logs derived permeability, there are two elements to be calculated: KHw (Permeability of sands units filled with water * thickness of these sand units), and KHhc (Permeability of sands units filled with hydrocarbon *thickness of these sand units). The ratio of KHw/(KHhc+KHw) provides a mean of estimating percentage of the expected water production. This approach has been validated with actual water cut from production data.
Using mathematical product of KHhc*Phie (effective porosity)*(1-SW) provides a mean to rank the wells in terms of expected Hydrocarbon productivity, which then can be contoured and utilized for reservoir fracturing program of the reservoirs in promising wells.
Integrity Management of a Complex LNG facility
Authors: Zaki Mohammad , Sijm Albertus 
Published: May 2016

Abstract

Description
RasGas Company Limited ("RasGas") employs a Facility Integrity Management System (FIMS) whose primary objective is to create a frame work system to maintain the physical and functional integrity of RasGas critical assets.
Programme design starts with grouping equipment by programmes aligned with equipment classes such as structures, pipelines and machinery. Equipment is prioritised by determining its criticality to operations based on health, safety, environment (HSE) and business consequences. Risk-based plans, the so called equipment strategies, are developed to mitigate risks and maintain the desired level of integrity and reliability. These equipment strategy activities are then built into an overall Integrity Programme that includes objectives, roles and responsibilities and practices to ensure operational integrity through the operating life of the equipment.
This paper will explain the various aspects and objectives of the system, in particular the benefits of having such a framework in place, managing risk-based inspections, early risk identification, the continuous improvement cycle through data analysis and risk screening non-performed preventive maintenance activities.
The Facility Integrity Management System within RasGas would be described with the challenges faced and the lessons learnt during implementation. Challenges in the programme design, development and implementation will be highlighted as well as the strategies and decisions made to overcome these. Particular focus will be given to learnings in the development, implementation and sustainment of equipment strategies, early risk identification and system management.
Low-Salinity Polymer Flooding: Improving Polymer Flooding Technical Feasibility and Economics by Using Low-Salinity Make-up Brine
Authors: Vermolen Esther C. M. , Pingo Almada Monica , Wassing Bart M. , Ligthelm Dick J. , Masalmeh Shehadeh K. 
Published: May 2016

Abstract
Polymer flooding is a mature EOR technique, which is successfully applied in both sandstone and carbonate reservoirs. In ongoing polymer projects, make-up brine is either formation water, sea water or any available water sources like deep or shallow aquifers. In this paper we focus on the use of low salinity water as the make-up brine. The objectives of combining low salinity flooding (LSF) with polymer flooding are three-fold:Using low salinity brine reduces the amount of polymer required to obtain the target viscosity, which may lead to significant cost reduction.Combining the benefit of low salinity flooding with polymer flooding leads to higher oil recovery over conventional polymer flooding.Enhancing the elasticity of polymers by using low salinity brine which may lead to reduced Sorw and increased oil recovery.
In addition to the objectives mentioned above, the use of a low-salinity make-up brine can give other benefits, such as better polymer stability (especially at high temperatures), lower sensitivity to polymer shear degradation, lower polymer adsorption and lower scaling and souring tendency.
The paper will presentExperimental procedures for investigating the potential benefits of low salinity polymer on both the required polymer concentration and the oil recovery.Experimental results for several field casesDe-risking activities that were undertaken to mitigate any potential negative impact of using low salinity polymer, in the areas of clay swelling, polymer shear sensitivity, mixing and adsorption.
The paper concludes that low-salinity polymer flooding can significantly improve existing and anticipated polymer flooding projects by reducing polymer volumes and/or increasing oil recovery. Low-salinity polymer flooding provides opportunities to apply polymer flooding in high-salinity and high-temperature reservoirs, for which polymer flooding with produced or formation water would be technically unfeasible or uneconomic.