bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Compartmentalisation in the JG Field – Western Desert Egypt
Authors: Hoogerduijn Strating Eilard H. , Postuma Willem 
Published: June 2014

Abstract
The JG field is located in the North East Abu Gharadig (NEAG) Basin of the Western Desert in Egypt. With first production in 2002, it is the first commercial discovery in the Middle Jurassic Lower Safa Reservoir Units in this basin. Oil and gas are produced from the tidally influenced estuary channel deposits in the Lower Safa A Unit and oil from the massive braided fluvial channels in the Lower Safa C Unit.
At first, the field was believed to consist of one single hydrocarbon column. However based on production behavior and additional well information it became apparent that the field was highly compartmentalized in the vertical and horizontal domain. Since then multiple data sources have been leveraged in order to obtain better compartment definitions: 3D seismic, logs, PVT data, geochemical fingerprinting, repeat pressure surveys and production data.
The boundaries between the reservoir compartments are defined by a combination of faults and stratigraphic heterogeneities. Although clear in places, some compartment boundaries can only be defined from non-geological data sources. Understanding these heterogeneities and compartment boundaries is essential for optimizing the field development.
Like so many fields the JG field proved to be more complex than initially expected. It is argued that extensive data gathering, in particular in the early field development, is essential in helping to timely identify and properly define such complexities.
Oil Recovery from Matrix during CO2-Foam Flooding of Fractured Carbonate Oil Reservoirs
Authors: Fjelde Ingebret , Zuta John , Duyilemi Olawale Victor 
Published: June 2014

Abstract
The recovery of oil during CO2 flooding of fractured carbonate oil reservoirs strongly depends on the transport of CO2 from the fracture to the matrix. Molecular diffusion of CO2 from the fracture to the oil in the matrix will therefore affect the rate of oil production from the matrix to the fracture. CO2-foaming agents have been shown to increase the macroscopic sweep efficiency in CO2 floods. However, whether the foaming agent either increases or decreases the rate of oil production from matrix to fracture needs to be understood.
The effects of a CO2-foaming agent on the rate of oil production during CO2 flooding of fractured carbonate oil reservoirs at reservoir conditions have been studied in a fractured model. The fracture model was created by transferring the waterflooded core plugs into stainless steel cells with an annulus space around the core plugs. The fractures were flooded by injecting CO2 gas, co-injecting CO2 gas and aqueous foaming agent solution, or injecting aqueous foaming agent solution outside the core plugs. CO2 bulk diffusion coefficients for synthetic seawater, stock tank oil and an aqueous solution of a CO2-foaming agent were determined using the pressure decay method.
Co-injecting CO2 gas and aqueous foaming agent solution was found to give slightly higher oil recovery than CO2 injection. Bulk CO2 diffusion coefficients measured in synthetic seawater and aqueous solution of foaming agent show that the tested foaming agent does not any significant effect on the transport of CO2 at the experimental conditions used. For the CO2-synthetic seawater and CO2-stock tank oil systems the bulk diffusion coefficients were estimated to be of the same order of magnitude as published in literature at reservoir conditions.
Alteration of Thermodynamic Equilibrium and Fluids-Rock Interactions during Acid Gas Injection into a Carbonate Sour Oil Reservoir
Authors: Ceragioli P. , Gianelli G. 
Published: June 2014

Abstract
An increasing number of prospects are concerning sour fields, whose development involves complex technologies which become highly attractive in the present high oil price regime. However the development of such reservoirs requires to properly handling the acid components of the reservoir fluid in order to avoid any environmental impact, so that the acid gas reinjection into the reservoir itself becomes one possible way to develop such fields. The technology, if properly handled, in many cases may be able to combine environmental preservation needs with enhanced oil recovery capabilities.
The development of sour reservoirs, and even more the reinjection of their sour produced gases, possibly increased of their acid concentrations, involves a complex phenomenology when compared with the normal reservoirs. Unlike what is usually accepted for non-acid fluids, mass transfer between sour/acid fluids and the connate brine cannot be neglected anymore, if not for their absolute amount, because of their possible significant effects. When a sour/acid fluid contacts the connate brine, significant amounts of its acid components dissolve into the aqueous phase changing its overall composition. The acid components may alter the equilibrium between the reservoir rock and the connate brine, thus driving possible interactions with the formations rock. The thermodynamic and chemical equilibria involved in this fluid-rock interaction process have been evaluated for a specific real case, and presented in this paper. By changing the pH of the connate brine, carbonatic minerals dissolve and the formation porosity increases, thus leaving the chance of more favourable injection conditions.
The quantification of these effects is relevant to well injectivity and stability. In fact, in carbonatic reservoirs, calcite dissolution appears to be the main geochemical effect, enhancing injection conditions. Connate water vaporization also make inejction easier, while salts precipitation could obstacolated it. However, when small amounts of everywhere immobile connate brine permeates a low porosity rock, the amount of dissolved calcite has revealed to be very low, so that any possible improvement is expected to be very limited.
Here a static approach, applicable to other sour carbonate oil reservoirs, where no connate water mobilization is expected, has been outlined and the conclusions, here referred to a specific case, can be easily generalized.
Bit Balling Mitigation in PDC Bit Design
Authors: Wells Michael , Marvel Tim , Beuershausen Chad 
Published: June 2014

Abstract
Historically, parameters like junk slot area (JSA), face volume (FV) and hydraulic horsepower per square inch of bit area (HSI) have been used to empirically predict the balling performance of drill bits. These performance gauges, however, generally produce inconsistent results. This paper presents new design features, guided by numerical predictions and the physical properties of actual PDC bit cuttings that reduce bit balling in PDC bits while drilling shales in water-based drilling muds. Validated by drilling simulator tests and field results, the new design criteria are shown to provide consistent reliable methods to reduce PDC bit balling.
The new design methods employ empirical design rules that govern the allowable proximity of two adjacent blades (pinch points) and the profile of the junk slots. These methods are shown to increase the maximum achievable ROP (that ROP where bit balling just begins) by as much as an order of magnitude. Highly controlled and repeatable drilling simulator tests show that failure to employ the new design rules consistently results in premature bit balling. The drilling simulator provides accurate results for bit sizes up to 12 1/4 in. although the principles most likely apply to all bit sizes.
Additionally, studies using computational fluid dynamics (CFD) in concert with drilling simulator tests indicate that the maximum achievable balling ROP of a PDC drill bit is increased with increased fluid velocity across the cutting structure. The correlation is shown to be valid over a wide range of bit types and sizes. The new bit designs incorporate strategic nozzle placements and new nozzle designs that improve PDC drill bit performance by increasing the fluid velocity across the cutters.
Improved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate Environment
Authors: Contreiras K. D. , Van-Dùinem F. , Weinheber P. , Gisolf A. , Rueda M. 
Published: June 2014

Abstract
The combination of low permeability, oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result.
The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low double or single-digits, saturation pressure is usually within a few hundred psi of formation pressure and borehole stability indicates that the wells must be drilled with oil base mud.
In the course of several penetrations of the Pinda formation a number of attempts were made to acquire representative formation samples but were stymied due to either excessive drawdowns that corrupted the fluid or by excessive contamination levels that rendered the samples unsuitable for laboratory analysis. Clearly a more flexible solution was required.
In this paper we review the learnings from previous attempts in the Pinda. We show the pre-job modeling that was done to predict the required flow rates and the anticipated drawdowns. Ultimately a two-step solution was used. We first ran a high efficiency pretest-only WFT in order to quickly gather formation pressure data and mobility data. This data was then used to design the sampling string which was a combination of an inflatable dual packer with focused probe. We discuss the decision process that governed the choice of pump, displacement unit, probe and packer. We pay particular attention to the unique pump configurations that were required to effectively manage the drawdowns when using the probe and also to allow sufficient flow rate when using the dual packer.
We conclude with a summary of recommendations and lessons learned for sampling in such an environment.
Modeling Production and Evaluating Fracture Performance in Unconventional Gas Reservoirs
Authors: Cipolla Craig L. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Abstract
This article examines issues with forecasting and evaluating production from unconventional gas reservoirs such as those in the Barnett shale. How can reservoirs be commercial with matrix permeability measured not in millidarcies or even microdarcies (10-3md), but nanodarcies (10-6md)—typically, 10 to 100 nanodarcies? The key is maximizing the reservoir area that is connected to the wellbore by creating a very large manmade- fracture network. But how do we create a fracture network? The answer is large-volume high-rate hydraulicfracture treatments that use water and small-mesh proppant to "activate" or stimulate the existing natural fractures or rock fabric. The created fractures are far from the classic "planar" model; they are large, complex flow networks that typically encompass 50 acres or more where the rock has been "broken." Gas production is a function of the number and complexity of fractures created, the effective fracture conductivity, and the matrix permeability. Understanding the relationship between gas recovery and fracture complexity, fracture conductivity, and matrix permeability is a key component of economic shale-gas development. This article will highlight the application of reservoir simulation to model production in shale-gas reservoirs, providing significant insights into these relationships that can improve stimulation designs, completion practices, and field-development strategies. Currently, most shale-gas resources are being developed with horizontal wells, and the reservoir simulations in this article focus on horizontal completions.

Introduction
The exploitation of unconventional gas reservoirs has become an ever increasing component of the North American gas supply. Gas shales are organic-rich shale formations and are apparently the source rock as well as the reservoir. The gas is stored in the limited pore space of these rocks, and a sizable fraction of the gas in place may be adsorbed on the organic material. The success of the Barnett shale has led to the development of other shale plays in North America, including the Woodford, Haynesville, Fayetteville, and Marcellus. The natural-gas resource potential of gas shales is estimated to be between 500 and 1,000 Tcf (Arthur et al. 2008).
Microseismic Monitoring: Inside and Out
Authors: Warpinski Norm 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Abstract
Since its inception in the 1970s and its commercialization circa 2000, microseismic monitoring has proved to be an invaluable tool for understanding underground processes. While its most common and notable use has been hydraulic-fracture mapping, it also is used for reservoir monitoring of thermal processes, drill-cuttings injection, geothermal hot-dry- rock stimulations, reservoir surveillance, and many other processes in oil and gas and mining.
Fig. 1 shows a typical layout for a monitoring test, with the offset monitoring well at some reasonable distance from the fracture (inset) and a receiver array somewhere near the depth of the fracture treatment. Because the amplitude of the microseism decays with distance, there is a maximum monitoring distance that can be used in any test with respect to both horizontal and vertical positioning. Designed correctly, this type of monitoring can provide information on fracture height, length, azimuth, asymmetry, dip, and complexity, which can be used to optimize the fracture design and field development.
To most outsiders, the entire process of microseismic monitoring appears to be something of an art, and the "what," "why," and "how" details are not very clear even though there have probably been more than 6,000 fracture treatments monitored since 2000, in rocks ranging from tight sandstones and gas shales to carbonates and even volcanic, and at depths ranging from several hundred feet to more than 13,000 ft. The purpose of this article is to lay out a basic framework for planning, executing, analyzing, and interpreting a microseismic mapping project and, hopefully, add some rigor to the process that can be used for guidelines or standards.

Overview
Basically, microseismic monitoring is the placement of receiver systems in advantageous positions from which small earthquakes (microseisms) induced by some downhole process can be detected and located to provide geometric and behavioral information about the process. In the case of hydraulic fracturing—the process of primary concern here— a sensitive-receiver array having numerous levels typically is placed in an offset well at a depth relatively close to the process. This array detects the seismic energy generated by the microseism by use of three-component geophones or accelerometers, and then algorithms are processed to locate the "event" using an assortment of information obtained from compressional (P-wave) and shear (S-wave) arrivals detected by the array.
Parallelization of a Commercial Streamline Simulator and Performance on Practical Models
Authors: Batycky R. P. , Förster M. , Thiele M. R. , Stüben K. 
Published: June 2014

Abstract
We present the extension of a serial execution commercial streamline simulator to mulit-core architectures based on the OpenMP programming model and its performance on various field examples. This work is an extension of recent work by Gerritsen et al. (2008) in which a research streamline simulator was extended for parallel execution due to its intrinsically parallel algorithm.
We identified that the streamline-transport step represents the bulk of the run time (65%-85%). It is exactly this step that is straightforward to parallelize owing to the independent solution of each streamline that is at the heart of streamline simulation. Because we are working with an existing large serial code base, we used specialty software to quickly and easily identify variables that required special handling for implementing the parallel extension. Minimal rewrite to existing code was required to extend the streamline-transport step to OpenMP. As part of this work we also parallelized an additional 2% of the runtime code which included the gravity-line solver and some simple routines required for constructing the pressure matrix.
We tested our parallel simulator on a variety of models including SPE10, a Forties UK oil/water model, a Judy Creek waterflood/WAG model, and a Middle East dual-porosity model. We noted speedup factors of between 2.5× to 3.5× for 8-threads. In terms of real time, this implies that large-scale streamline simulation models as tested here can be simulated in less than 4 hrs. We noted speedup scaling results that were reasonable when compared with Amdahl's ideal scaling law. Beyond 8-threads we did observe reduced speedups and attribute this to memory bandwidth limits on our test machine (AMD 8× Opteron 8218 2.6Ghz dual core).
Remote Sensing, Fuzzy Logic and GIS in Petroleum Exploration
Authors: Taheri S. Reza 
Published: June 2014

Abstract
To reduce the exploration costs for hydrocarbons during the reconnaissance stage of exploration, satellite images and available surface data could be used. This paper identified three significant surface patterns which are considered promising; surface temperature derived from satellite data, vegetation cover and gas geochemistry. These were integrated and their correlation to the presence of petroleum investigated.
By employing GIS and fuzzy logic a dynamic model was developed which could be applied to any new petroleum exploration target using variable input data of that particular exploration target.
A selected study area consisted of 53 existing petroleum-reach areas within 20 ASTER (Advanced Spaceborne Thermal Emission and Reflection Radiometer) Granules. Each granule covers an area of 3600km2 (60 km x 60 km) of land in onshore Iran. 20 ASTER scenes over the study area were purchased from NASA and surface thermal data over these existing fields were retrieved from the satellite images.
The direction of land surface temperature (thermal anomaly) was analyzed using variograms which correlated well with the direction of petroleum reservoir locations. Variograms were used to study the trend and direction of thermal anomaly behaviour over the reservoirs. Many contributing factors such as geological units, meteorological conditions, time and the seasons of ASTER data acquisition, thermal conductivity of stratigraphic units of the study area and other sources (hot springs, power stations, producing wells etc…) were considered and fuzzy membership values for corresponding pixels in the processed ASTER images were assigned accordingly.
Spatial pre-processing and registrations of satellite data, together with spatial analyses consisting of Land Surface Temperature (LST) retrieval from ASTER data and removing the false thermal contributors to LST, were among the key processing procedures applied for the thermal data layer in the proposed GIS system.
Complex Effect of Connate Water in Vapour Extraction Process
Authors: Etminan S. Reza 
Published: June 2014

Abstract
The objective of this work was to study the effect of connate water in the progression of the Vapor Extraction (VAPEX) process for heavy oil recovery. A large fraction of the physical model tests of the VAPEX process reported in the literature have been conducted without any connate water in the system. The absence of connate water was rationalized by suggesting that it has little or no influence on relative permeability of oil and since the vaporized solvent does not dissolve in water, there is no effect of water on the mass transfer process.
We have evaluated the effect of connate water on VAPEX performance using physical model experiments carried out in a visual model, with different connate water saturations. Butane was used as the solvent and fine Ottawa sand was used for packing the model to obtain permeability and capillary pressure values comparable to the field conditions. In addition to the visual observations of the size and shape of the vapor chamber, the rates of oil and gas production were monitored during the experiments.
The results show that connate water has a measurable effect on the process, both in terms of the shape of the vapour chamber and the drainage rate of the diluted oil. The presence of connate water causes faster spreading of the vapor chamber in the lateral direction and tends to increase the thickness of the mixing zone. This increase in the mixing zone thickness appears to result from capillarity driven fingering phenomenon. The mixing zone had a distinct uneven appearance that was similar to patterns generated by frontal instabilities in miscible displacements. The effect of connate water on drainage rate was an increase in the initial rate but a reduction in the rate subsequently. The presence of mobile water speeds up the communication between the two wells and leads to even faster spreading of the vapor chamber. Finally, the de-asphalting and oil upgrading was more significant in the presence of connate water.
Managing HSE Risk in Harsh Environment
Authors: Yusoff Nor Hashim , Yusof Mohd Radzuan 
Published: June 2014

Abstract
PETRONAS Carigali Sdn Bhd (PETRONAS Carigali) is a fully-owned subsidiary of Petroleum Nasional Berhad (PETRONAS), a Malaysian National Oil Company (NOC). PETRONAS was incorporated on 17 August 1974, while its E&P arm, PETRONAS Carigali, was incorporated on 11 May 1978. PETRONAS was originally formed with the intent to increase Malaysian participation in the E&P industry in the country.
However, PETRONAS has been actively expanding its activities beyond Domestic arena, especially in the E&P sector. PETRONAS, through its E&P arm PETRONAS Carigali, has expanded its business to more than 30 countries in South East Asia, Middle Asia, Middle East, Africa and America. After being an oil and gas player for just more than 30 years, PETRONAS Carigali has moved from Domestic Player to International since 1990.
Being a global player, knowledge and experience is crucial in ensuring successful ventures. In this respect, PETRONAS being a ‘young’ Company compared to other major global players who have been in existence for more than 100 years, has a proven track record of successful ventures including being listed in Fortune 500 as well as obtaining excellent HSE performance.