bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Controlled Salinity Waterflooding in Carbonates
Authors: Al Mahrouqi D. A. , Vinogradov J. , Jackson M. D. 
Published: September 2016

Abstract
The impact of brine composition on rock wettability and oil recovery in carbonates has been an area of research in recent years. Many studies have reported contradictory results concerning the impact of water injection salinity and composition on oil recovery. The zeta potential, which is a measure of the electrical charge at the mineral surface, is highly variable in carbonates, depending on the ionic composition of the pore water. The zeta potential controls the magnitude and polarity of the electrostatic interactions between the mineral surface and polar species in the brine and oil; it also controls the magnitude and polarity of the streaming potential, an electrical potential which arises in response to pressure gradients across saturated rocks.
Here we report the use of streaming potential measurements to characterize wettability and optimize injection brine composition during controlled salinity waterflooding (CSW) in carbonates. Crude oils, natural carbonate core samples and synthetic brines (equivalent to formation, seawater and modified seawater compositions) are used to evaluate wettability and CSW effect. We use the streaming potential measurements to determine the zeta potential, and correlate changes in zeta potential with changes in wettability and improved oil recovery. To predict the optimum brine composition for CSW requires knowledge of the zeta potential and how this responds to changes in brine composition. Such knowledge can be obtained using the streaming potential method reported here, which is much cheaper and quicker than conducting numerous multiphase coreflooding experiments and varying the brine composition on an ad-hoc basis.
Comparative Analysis of Various Failure Theories for Borehole Breakout Predictions
Authors: Morita Nobuo , Nagano Yu 
Published: September 2016

Abstract
Numerous papers have been published for predicting the borehole breakout problems (McLean 1990; Zoback 2007; Ewy 1999). The original theory proposed by Zoback (Zoback 2007) used the Mohr-Coulomb failure theory with a linear elastic stress strain relation. Initially, it was applied to igneous rocks and large diameter boreholes. With these original applications, the linear Mohr-Coulomb theory predicted the breakout width within a reasonable accuracy. Recently, the applications have been expanded to breakout problems for shales, mudstones and sandstones. However, there are some drawbacks. For sedimentary rock applications, the Mohr-Coulomb failure theory significantly over-predicts the breakout width. In addition, strong rocks show significant non-linearity before failure, hence, we need to artificially increase unconfined rock strength (UCS) and friction angle. The theoretical breakout width cannot be matched with the breakout width observed from the image logs unless these adjustments are made. Using the image logs and the rock strength measurements obtained from several fields, comparative analyses were conducted for various failure theories with linear and non-linear stress strains. These failure theories include Mohr-Coulomb, Drucker-Prager, Lade, Modified-Lade, Mogi and critical plastic strain. The authors also compared linear and non-linear stress strain theories. The authors estimated the increase in UCS necessary to match the breakout widths observed from the image logs obtained from several fields. The authors utilized caliper logs to compare the breakout depths as well.
The results show that if a linear stress strain relation is used, UCS must be increased artificially by 1.09-2.25 times. This increase is as much as 2.25 times for the Mohr-Coulomb failure theory. On the other hand, if a non-linear stress strain relation is used, no artificial increase is necessary except for the Mohr-Coulomb failure theory. In addition, the effects of temperature change and shale swelling are varied depending on the failure theories. These effects are supposed to de-stabilize the boreholes. Interestingly, the borehole stability differs depending on the failure theory used. Moreover, the actual breakout depths are always deeper than those predicted with a linear stress strain theory while they are shallower than those predicted by a slip line failure theory.
This paper compares the merits and demerits of each failure theory when applied to borehole breakout problems. Many triaxial tests were conducted to determine the stress strain and failure envelopes. The predicted breakout widths were compared with the measured breakout widths from the image logs. This kind of comprehensive evaluation (theoretical, experimental and field analyses) has not been performed in previous studies.
Utica Well Performance Evaluation; A Multi-Well Pad Case History
Authors: Shelley Robert , Shah Koras , Underwood Keith , Davidson Brian 
Published: September 2016

Abstract
Understanding Utica formation hydraulic fracture and completion effectiveness is problematic given the wide variation in geology, hydrocarbon maturity and reservoir characteristics. Quite often, a positive production response from a well may be incorrectly credited to the completion and frac design when in reality the production was dominated by favorable reservoir characteristics. Conversely a poor production response from a well may be attributed to the completion and frac design when in fact poor reservoir quality is the controlling factor. The subject of this paper are detailed analysis of three direct offset wells which were performed by experienced engineers with reservoir knowledge for the purpose evaluating completion and frac effectiveness.
When adequate production became available from these wells a detailed engineering evaluation was performed on each to estimate reservoir and frac characteristics. These evaluations consisted of (1) perform frac pressure matching for all treatments with a 3-D frac model, (2) perform production history matching on all phases with a numeric reservoir simulator and (3) estimating conditions within the fracture over time as the wells are produced. The methods used to perform these evaluations are not new, however they currently are underutalized by the industry today.
The evaluations performed indicate that completion, frac design, operational and production issues can all significantly influence Utica well production and economics. In addition the findings show that in this case the hydraulic fractures are not very efficient.1–9 This inefficiency results in a relatively short effective fracture length which causes loss of productivity, recovery and return on investment.
Geopolitics of Unconventional Resources Outside North America
Authors: Charlez Philippe A. 
Published: September 2016

Abstract
With the shale gas (SG) and Light Tight Oil (LTO) development, the US has become gas independent and has halved oil dependency. This revolution was based on four pillars: knowledge of the subsurface, open and competitive market, full government support and favorable mining law.
Outside the US, SG and LTO development cannot rely on the same pillars. The purpose of this paper is to analyze the motivations and the possible blocking factors that could encourage five countries/regions to develop (or not) their unconventional resources.
Gas exporter until 2004, Argentina imports today gas from Bolivia and LNG from the Middle East in a subsidized local market. These imports could ultimately stifle Argentina's public finances. Consequently, the authorities want to quickly develop the huge potential of the Vaca Muerta, one of the best source rocks in the world. Nevertheless, the cost of imported equipment and products as well as the monetary stability of the local currency could be blocking factors.
Saudi Arabia, the world's second largest oil producer, consumes nearly 1 Mbopd to satisfy the increasing electricity demand. Unlike Iran or Qatar, Saudi Arabia has not sufficiently developed its gas potential. Therefore, it intends to extract its unconventional resources in the future, in particular the source rock of the Ghawar field. Water supply for hydraulic fracturing could be a blocking factor.
China is facing a double challenge: reducing its GHG emissions by displacing its power generation from coal to gas/renewable while keeping its energy dependence at an acceptable level. Therefore, China is looking forward to develop its unconventional potential which is expected to be comparable to that of North America. The resources are located in the Tarim Basin (North West) and the Sichuan Basin (South East). The depth, the complexity of geological structures, the remoteness and the aridity of the basins make the field operations difficult and expensive.
Russia is now 70% dependent on its oil and gas revenues. The potential of Russia's unconventional resources is mainly associated with the gigantic Bazhenov formation located in Western Siberia. The Russian authorities, who wish to offset their declining conventional fields, have launched a legislative process associated with tax incentives. Permafrost and subartic conditions can be blocking factors as drilling and fracturing are required all over the year.
In the last 30 years, competitiveness in Europe was weighed down by an oil and gas bill that represents 75% of its debt. Developing the local resources to avoid becoming 100% dependent on the suppliers is of strategic importance. However, the development costs, the regional urbanization and the societal opposition are potential blocking factors.
A Step-Change for Single Well Chemical Tracer Tests (SWCTT): Field Pilot Testing of New Sets of Novel Tracers
Authors: Al-Abbad Mohammed , Sanni Modiu , Kokal Sunil , Krivokapic Alexander , Dye Christian , Dugstad Øyvind , Hartvig Sven , Huseby Olaf 
Published: September 2016

Abstract
SWCTTs are often used to assess residual oil saturation (Sor) or remaining oil saturation (ROS) in the near well-bore region before initiating enhanced oil recovery (EOR) or improved oil recovery (IOR) projects. The technique is based on the chromatographic separation of two different tracers. One oil/water partitioning tracer partly hydrolyzes in the reservoir, to generate a secondary non-partitioning water tracer. Most of the reported SWCTT operations typically use ethyl acetate (EtAc) as the primary tracer. Some of the challenges with the current set of chemicals used are their high flammability, poor detection limit (ppm range) and the large quantity required.
A new set of tracers has been developed to overcome these challenges. These were pilot tested in a giant carbonate reservoir undergoing peripheral water-flood to measure Sor prior to a field redevelopment project. The new tracers were field tested concurrently with the conventional EtAc method for comparison purposes. About 100 g (0.1 kg) of each of the new tracers were injected at different times and different ways during the conventional SWCTT operation. It is worth highlighting that tens or hundreds of kilograms of conventional SWCTT tracer are needed for a single operation.
This paper reviews the complete design and implementation of the test, operational issues, the analyses and the interpretation of the results. The Sor measured by each of the novel tracers compare well to that from a conventional SWCTT. The results also show that these tracers can be injected in pulse mode – at a very short time interval, thus reducing the operational time needed for pumping the chemicals. In addition, the test results suggest that several tracers with different partitioning coefficient may be deployed to investigate different depths of the reservoir.
The pilot further demonstrate that many tracers with different properties may be deployed simultaneously without risking interference with the Sor measured during the test – this may revolutionize measurements of saturations in SWCTT operations.
Cubic Law Evaluation Using Well Test Analysis for Fractured Reservoir Characterization
Authors: Denetto S. , Kamp A. M. 
Published: September 2016

Abstract
In fractured reservoir, the use of the so-called cubic law represents a method to describe fluid flow through fractures and to estimate effective fracture porosity from effective fracture permeability and matrix block size. The method supposes perfect fracture connectivity. In practice, however, it often underestimates field fracture porosity. This paper explores the relation between fracture porosity, fracture permeability and matrix block size using field, and in particular well test, data.
We used field data coming from four naturally fractured sand-stone reservoirs in foothills. Values of storativity ratio (ω) and inter-porosity flow coefficient (λ) coming from thirty-three pressure buildup derivatives interpretations are listed and used to estimate fracture porosity and matrix block size. The effective permeability associated to each well test, which is obtained from the stabilization of the pressure derivative, was also recorded. A non-linear regression was put in place in order to correlate fracture porosity, matrix block size and effective permeability. Obtained fracture porosities and block sizes are similar to values from other sources, such as thin section analysis and image log data.
The most significant finding is that field data can be correlated by introducing in the cubic law a correction parameter that increases fracture porosity by about two orders of magnitude. The reason for deviation from the theoretical cubic law can be threefold: first, the cubic law considers the entire hydraulic aperture of the fracture as contributing to the fluid flow, while in reality the flow may be hindered by presence of cement in-filling the fracture (thin section data supports this assumption); secondly, the cubic law assumes a perfectly connected fracture network, while in real cases some fractures may die out without intersecting any other fracture; thirdly, transient flow effects and distribution of block sizes may lead to a less well pronounced dip in the derivative, which may be interpreted as a larger fracture porosity when using a pseudo steady-state model for analysis. The correction parameter is likely not universal, and will depend on the degree of fracture in-fill and connectivity in a given field.
The work presented in this paper provides fracture permeability, fracture porosity, and block size estimates for the given type of environment. It issues a strong warning with respect to the application of the cubic law to estimate fracture porosity, and proposes a corrected cubic law expression that gives more accurate results. The methodology is useful for characterizing fracture porosity, a parameter that is notoriously difficult to measure.
Successfully Delivered Drill-In, Clay-Free Fluid with Innovative Delayed Acid Breaker for the Longest Horizontal Wells in Offshore Abu Dhabi
Authors: Angelo S. D , Shabaka H. , Hamed M. , Vinci M. , El Salam M. Abd 
Published: September 2016

Abstract
Extended reach drilling well design is one of the most critical designs to consider for achieving maximum reservoir contact and increasing well production. This paper demonstrates the methodology for delivering an organophillic clay-free, invert emulsion fluid system using calcium bromide in the internal phase, and discusses an innovative breaker package containing an acid responsive surfactant. Results show a significant reduction in metal/metal and metal/formation friction. Furthermore, no change in wettability has been recorded after the formation has been treated with the breaker.
Precise quantitative and qualitative testing methods provided milestone results. Phases of design began with API testing, followed by stressing the fluid beyond the normal downstream conditions, then finally using the return permeability apparatus. Testing all fluids against an artificial core, followed by a natural core, gave the operator the projections required to drill such complicated wells. Intelligent software helped to replicate the actual conditions precisely enough to drill and complete these wells with minimum friction, as well as to simulate effective hole-cleaning practices to help enable optimum equivalent circulating density (ECD) management.
From planning to execution, valuable observations were recorded. The use of this system resulted in successfully drilling and completing the longest horizontal well in offshore Abu Dhabi. During 2.5 months of drilling and completing time, no critical path time was wasted because of uncertainty or changes to the approved plan. As a result of using non-aqueous fluid, the friction factor was reduced to 0.07. Furthermore, no fluid treatment was necessary to maintain that lubricity beyond the physical properties of the system itself. The unique composition of the delayed acid breaker used in combination with acid responsive surfactant removed any skin or crushed zone around the wellbore. The recorded well producibility was beyond the expectation, and no acidizing was required.
For nearly a decade, lubricants associated with water-based fluid types have been engineered, but inver emulsion fluids had not been considered because of their low initial density and issues associated with stimulating the reservoir. This system provides a successfully designed and executed organophillic clay-free, invert emulsion fluid, as well as a state-of-art delayed acid filter cake cleanup package to maximize the return on investment.
Retrofit Gas-Lift Straddles in the North Sea
Authors: Masson Graham , Bill Bjorn , Campbell Atholl , Mackay Andrew , Brodie Alan , Emslie Murray , Isaj Albert 
Published: September 2016

Abstract
Deciding on the optimum design for any new well is a complex task, made often more difficult by a wide range of technical uncertainties. Getting the completion design right is particularly important for subsea wells, where the cost of intervention can be prohibitive.
After several years of production, it is common to encounter significantly different reservoir and well conditions than were initially predicted at the time of the original well completion and artificial-lift designs. Gas-lift is not always required until later in the well life. While some gas-lift valves have an impressive reliability record, some can fail or be deemed sub-optimal for the well conditions and necessitate retrieval to optimise well performance or to reinstate well integrity.
Retrievable straddle packers are commonly used to isolate water and/or gas production in the sandface completion or reinstate well integrity in the upper completion. This paper will review different methods used to reinstate gas-lift, and describe the gas lift design process and straddle configuration using case studies from the North Sea.
In particular, Premier Oil undertook a subsea well intervention campaign to restore production, which had ceased following the suspected failure of the gas-lift system. Analysis of the well performance data suggested that one or more gas-lift valves were inoperable and that the original valve depths were not ideal for the encountered reservoir conditions.
The operation was performed from a light well intervention (LWI) vessel, deploying a retrievable Interwell straddle and PTC GoLift™ Straddle system, installed in the tubing across and between the existing side pocket mandrels, creating a retrofit, triple packer, gas-lift straddle.
Premier performed a safe and successful LWI operation, returning the well back to its full production potential, having met all well intervention objectives. Running the retrievable straddle packer solution with PTC's GoLift™gas-lift system helped to optimise production and saved the need for a costlier rig-based upper completion workover.
This paper will further look at the design and development of these technologies, examine in depth one case study for the Brenda D3 design and installation.
Successfully Developing Fields in a Mature Region Whilst Revenues are Going Down, a Non-Operating Partner Perspective
Authors: Schulte Ruud , Kreft Eric , van Ewijk Eric 
Published: September 2016

Abstract
EBN - the Dutch state-owned Oil and Gas Company - has been working with a large number of International Oil Companies, (super)majors and smaller independents, that have been active within The Netherlands.
Over the years, field developments have become increasingly challenging as opportunities are smaller in volume and technically more complex; the low hanging fruit has already been picked. Since late 2014, the difficulty to bring remaining opportunities into production is exacerbated by recent oil and gas price trends.
E&P companies have learned from historic project performance and from each other, resulting in project management systems that in essence are look-a-likes. A typical project management system consist of a three stage gated approval process with a focus on good Front-End Loading, a focus on project team staffing, and on other Best-Practices. Although at least on paper each individual project is undergoing extensive reviews at all the different gates, in reality our research observed significant differences in actual adherence to the proscribed work processes, not only by company but also between projects. This variety results in a wide range of project performance: from very successful to train wrecks.
In 2012 our Non Operated Ventures (NOV) management system was overhauled in order to stimulate the profitability of our field developments. Changes made included an earlier-on involvement to ensure that a broad range of concepts is being considered with an emphasis on novel cost-efficient concepts. Finding the delicate balance between hands-off, eyes only has contributed to a drastic improvement in project performance with demonstrated costs savings of up to 50 %. Cost savings that –given the current price trends - are required to be able to sanction and commercially successfully execute forthcoming field development plans.
This paper will discuss in detail our look back analysis, including earlier projects with typical E&P project results (cost and schedule overruns and the like), but also the results of recently more successfully completed projects and most importantly; the drivers that make the difference.