bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Gas-Saturation Determination in Abu Dhabi Offshore Reservoirs Through Integrated Pulsed and Thermal Neutron Log Approach
Authors: Al Marzouqi Mariam , Al-Farisi Omar , Amer Mohammed Mostafa , Al-Habshi Ali , Lund Espin 
Published: December 2007

Abstract
Quantifying gas saturation in carbonate formations through cased logging remains an elusive objective. Unsolved gas saturation quantification in cased hole was always thought to be due to unknown or uncontrolled borehole completion, casing, cement, acidizing, perforation, invasion and/or formation damage. Several techniques have been developed in the past to correct for the cased-hole thermal neutrons logs in an attempt to normalize the data through laboratory experiments, correction charts or open hole computer processing of effective porosity (PHIE).
In Abu Dhabi offshore lower Cretaceous reservoirs, joint petrophysical & reservoir engineering efforts have shown that most of these automated corrections and/or normalizations are not capturing the real environmental changes from open-hole (OH) to cased-hole (CH). The reasons behind it are:
Open-hole neutron logs were not considered as the reference; instead, old technique uses PHIE (Effective Porosity). Casing and cement corrections are based on a homogenous isotropic model. There was no proper resolution matching between OH and CH and edge effect corrections applied to pulse neutron data.
Therefore, new technique is developed and presented in this paper; it is called "HYDGO" (Hydrocarbon Density Determination for Gas and Oil). This technique utilizes several back-to-back OH and CH log data information to carefully eliminate the CH environment effect. This is done by developing multi-variable-correction model that incorporates OH bulk density, water saturation, thermal neutron porosity and invasion. This procedure has led to the development of hydrocarbon density and gas saturation determination.
Abu Dhabi Heterogeneous Carbonate: New Upscaling Approach of Detailed 3D Geological Model
Authors: Elsaid Mohamed Elhami , Belgaied Adel , Al-Ginibi Faisal , Al-Farisi Omar 
Published: December 2007

Abstract
Through careful design of simulation model grids, and in order to overcome the computing limitations reasons, the main objective of the up-scaling process is to capture the flow characteristics, to retain the geological features and maintain the reservoir heterogeneity in both vertical and lateral directions in one of the major Carbonate oil field in Offshore Abu Dhabi, U.A.E.
The paper covers the geological modeling of the reservoir's complex heterogeneities, discusses and presents practical and efficient new method for upscaling from geological to reservoir model.
The challenge of Upscaling detailed 3D geological Model of multi-million-cell size into hundred thousands cell simulation model is well demonstrated.
In this regard, three upscaling approaches were adopted and validated against the roubst geological model. These methods are: (1) Up-layering visualization, the technique that provides reservoir engineers with optimal geologic layer-grouping schemes. (2) Geostatistical validation for the upscaled petrophysical data like Rock Types, Porosity, Permeability and Saturation attributes and (3) Validation through Streamline Simulation approach.
The use of this new upscaling approach ensures preservation and capturing of necessary geological details and reflects reservoir heterogeneity. Thus allowing realistic, representative and accurate reservoir simulation architecture to be used in Full Field Development plan scenarios. A feedback loop will be maintained between the simulation and geological
Thereby: validating and improving the geological model based on dynamic data.
Evolution of Sand Control Completion Techniques in the South Tapti Field
Authors: Holmes J. D. , Tolan M. P. , Hale C. 
Published: December 2007

Abstract
The stacked sands of the South Tapti field have presented completion challenges from field start-up in 1997 to the present-day. A large part of these challenges have been caused by reactive shales interbedding the sand bodies. This has had a persistent influence on the sandface completion design and, in particular, on the drilling and completion fluid systems.
The completion design has evolved from stacked cased hole gravel pack to open hole gravel pack designs. Non-gravel pack open hole designs are also being considered for the future to meet the challenges of drilling and completion at higher well angle. The field requires a mix of all these techniques to meet well objectives.
Laser Drilling Research and Application: An Update
Authors: Sinha Pankaj , Gour Aabhaas 
Published: December 2007

Abstract
The paper is an update to the current status of laser drilling technique - the first fundamental change to rotary drilling. We begin with a brief note on history of physical tests in 60's and 70's which were limited by the laser technology and low power available at that time. Seven lasers have been identified for potential use in the upstream oil industry. Each rock type has a set of optimal laser parameters to minimize specific energy as observed in the linear track tests. Current efforts are focused on underwater laser drilling.
Next, stress has been put on the basic scientific principles that can bring laser drilling within reach of an industry-supported prototype. Hence, the methods of delivering laser radiation and rock removal from wells drilled followed by parameters like feasibility, economics, benefits and environmental impact related to laser drilling have been discussed.
Laser drilling is found to be more efficient, cleaner way to drill and perforate wells through hard rock formations encountered at greater depths. The effects of the laser rock interaction on permeability have also been studied. Laser perforation resulted in permeability improvements. One of the major advantages of laser drilling is its potential to reduce drilling time. Lasers cut drilling time by not contacting the rock, eliminating the need to stop and replace a mechanical bit. Finally, we end with a discussion on the wider scope of laser technology for on-site tasks including cutting windows for side exiting casing or laterals, extended perforations that connect additional reservoir rock to the well bore, and removal of objects lost down hole that would normally require drill out or fishing operations.
Polyol Drilling Fluid: A Novel Solution To Curb Recurring Drilling and Completion Problems in Mature Sobhasan Field, Mehsana Asset, ONGC, India
Authors: Raza Khan M. S. , Pratap V. , Sharma K. C. , Anilkumar B. S. , Gupta A. K. 
Published: December 2007

Abstract
Sobhasan field is one of the oldest fields of Mehsana Asset, ONGC, India. Hydrocarbons are produced, mainly, from multi-layered reservoirs in Mehsana and Mandhali members of Kadi Formation. Being a mature field, the pressure of reservoirs has gone down to 0.7 MWE. These depleted reservoirs (0.7 MWE) are inter-bedded with pressurized shale sequences (1.18–1.20 MWE) and thick/fragile coal bands. With this type of pressure regimes, drilling of ‘S’ profile wells with conventional drilling fluids is a challenge. Recurrence of differential stuck-ups and coal-caving during drilling and ‘failure of logging’ during completion operations is a common feature. The paper presents how the application of tailor-made polyol drilling fluid along with improved drilling practices helped in mitigating the recurring complications.
The strategy to resolve such challenges required to either review the casing policy or change the profile of the well or bring in new drilling fluid system. First and second options were not feasible due to high heterogeneity in lithology and technical implications respectively. So the emphasis was given on the third option (i.e. use of KCl-PHPA-Polyol drilling fluid) along with improvement in drilling practices to resolve the prevailing problems. Extensive studies were carried out to formulate a tailor-made KCl-PHPA-Polyol drilling fluid.
The polyol drilling fluid was applied in two wells recently. Better drilling practices, while drilling coal sections, were adapted to avoid disturbance of coal sections. The apparent benefits are: saving of rig days, healthy bore hole, reduction in torque/drag, prevention of differential sticking, and smooth logging operations. The present paper is an endeavor to demonstrate how ‘polyol drilling fluid’ and ‘tailored drilling practices’ can complement each other in the completion of problematic ‘S’ profile wells smoothly. This proposal is an example of ‘Sharing Best Practices’.
Analysis of Hydrofracturing Efficiency
Authors: Vakhitova Aigul 
Published: December 2007

Abstract
Petroleum companies nowadays tend to increase oil production from low-permeability heterogeneous reservoirs. Commercial development of such difficult objects is possible with all modern stimulation methods involved including hydrofracturing. Decrease in flow friction near the wellbore and increase in filtration area as a result of fracturing lead to multiple increase in production well rates and injection well capacities. Besides recovery factor increases because of oil production from poor-drained zones and layers.
The purpose of this work was to estimate hydraulic fracturing efficiency by estimation of after fracturing well rate increase, by comparative analysis of well logging held before and after frac operation and by analyzing the well test. The task was to investigate factors of fracturing effectiveness. Also the principle of well selection for fracturing and their order in FDP was examined.
Data on Priobskoe and Krasnoleninskoe (Em-Egovskaya area) fields located in Western Siberia were used in this work.
Commissioning of Northeast Bab (NEB) Development Project
Authors: Saadawi Hisham 
Published: December 2007

Abstract
The North East Bab (NEB) Project has been recently commissioned by Abu Dhabi Company for Onshore Oil Operations (ADCO). The project is a grass root field development project to produce 110, 000 barrel per day. The project also includes facilities for water injection, high pressure gas injection as well as WAG. The oil production is from three separate oil fields; Al Dabbiya, Rumaitha and Shanayel.
Commissioning and start-up of the facilities were done by the company staff. This paper outlines the commissioning strategy adopted by the company and discusses the commissioning experience.
Integration of Microseismic Fracture Mapping Results With Numerical Fracture Network Production Modeling in the Barnett Shale
Authors: Mayerhofer M. J. , Lolon E. P. , Youngblood J. E. , Heinze J. R. 
Published: December 2007

Abstract
This paper presents the results of integrating microseismic fracture mapping with numerical production modeling of fracture networks in the Barnett shale. Microseismic fracture mapping has shown that hydraulic fracture treatments create large-scale fracture networks in the Barnett shale1–2. In this paper an approach is presented, where the fracture network measured with microseismic mapping is approximated with a numerical production simulator that discretely models the network structure in both vertical and horizontal wells.
The work includes a production history match of a vertical Barnett shale well, where the microseismic mapping results were directly used to approximate a fracture network in the reservoir simulator, resulting in an estimate of effective fracture network length, average fracture conductivity and effective drainage area. In addition, a parametric study for horizontal wells is presented to show how fracture network size and density, fracture conductivity, matrix permeability and gaps in the network affect well productivity. Simulations on the effect of fracture face damage along the network, the effect of non-darcy flow in the network, and tapered fracture network conductivity that decreases away from the well are also included. The numerical model was also used to simulate how a pressure buildup test would appear based on given fracture network properties, which could be a useful diagnostic to evaluate the effectiveness of the fracture network.
The results of this work illustrate how different fracture network characteristics impact well performance, which is critical for improving future horizontal well completion and fracturing strategies in the Barnett shale. This could include optimizing the number of fracture stages along the lateral, length of the lateral, treatment sizes, and perforation strategies as well as enhancing fracture network conductivity and the effectiveness of re-fracture treatments. The work also shows how microseismic mapping results can be integrated with production modeling, thereby providing a tool for more realistic infill drilling and well placement studies in the Barnett shale or similar types of reservoirs.
Dependence on Temperature, Pressure, and Salinity of the IFT and Relative Permeability Displacement Characteristics of CO2 Injected in Deep Saline Aquifers
Authors: Bennion D. B. , Bachu S. 
Published: December 2007

Abstract
Sequestration of CO2 in deep saline aquifers is a means with great potential for reducing emissions of this greenhouse gas produced from a wide range of industrial operations. The displacement characteristics of CO2 injected into deep saline aquifers are essential in that they control both the migration of CO2 and the available pore space in the reservoir at irreducible saturation conditions, yet very little information exists about these characteristics. This paper presents continuing results of a research study conducted by the authors to investigate the displacement characteristics of CO2-brine systems at reservoir conditions for cases specific to the Alberta basin and representative for intracratonic and foreland basins in North America. More specifically, the work reported here focuses on a controlled series of tests in which the effects of temperature, pressure and brine salinity were varied in a systematic manner to identify and quantify their effect on the interfacial tension between CO2 and equilibrium brine. The results indicate that the CO2-brine IFT decreases with increasing pressure, while increasing temperature and brine salinity have an opposite effect. These results were then extended under similar controlled conditions to consolidated porous media to investigate the effect of interfacial tension, as impacted by specific reservoir conditions of temperature, pressure and salinity, on the relative permeability character of CO2 displacing brine for a number of different interfacial tension conditions. The results are presented, and the significance with respect to the feasibility and optimization of CO2 sequestration in deep saline aquifers is discussed.
Evalution of Decrease in Productivity Indices of Production Wells in the Fields With Reservoirs Comprised of Highly Heteregeneus Carbonates
Authors: Dorfman M. B. 
Published: December 2007

Abstract
The productivity indices drop-versus-drawdown increase relationship has been fairly well known and described in the literature. This effect is most likely to be expected in the carbonate reservoirs with cavernous-fractured-matrix porosity and rock heterogeneity. It was observed to occur in the wells of Ardalin field and its satellites located in the north of the Timan-Pechora Oil and Gas Province during the well performance analysis. The discussed fields are highly prolific with the well flow rates as high as 1.500 m3 /day. The changes of productivity indices as an effect to increasing drawdown were not taken into account during well testing, modeling and production forecasts in the early phase of development. However, it becomes a necessity as the water production grows while the wells are converted from flowing to artificial lift with the electric submersible pumps, when the reservoir engineers need to achieve the optimal production rates and provide reliable production forecasts. Taking account of this factor will allow making the right choice of appropriate pumping equipment. The peak productivity of wells observed in the field appeared to be way below the original forecasts, which did not include the reservoir compressibility.
Application of New Fall-Off Test Interpretation Methodology to Fractured Water Injection Wells Offshore Sakhalin
Authors: van den Hoek P. J. , Volchkov D. , Burgos G. , Masfry R. A. 
Published: December 2007

Abstract
It is well established within the Industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected-either for voidage replacement or disposal-large fractures may be induced over time.
Unfortunately, not much work has been carried out to date to provide methodologies for predicting and measurement of the size of waterflood-induced fractures. This contrasts to the vast amount of work that has been done for stimulation (e.g. propped) fractures.
Injection Fall-Off (IFO) test analysis offers a cheap way to infer the dimensions of induced fractures from welltests. This paper presents a new methodology for IFO test analysis of fractured waterflood wells. This methodology derives the dimensions of induced fractures, and the extent to which these are contained to the target injection layer. Furthermore, the paper focuses on the application of this methodology to a waterflood offshore Sakhalin in the Russian far East.
The methodology is based on an exact solution to the fully transient elliptical fluid flow equation around a closing fracture with changing conductivity, face skin, and multiple reservoir mobility zones. It also captures the case that during closure the fracture generally shrinks from adjacent geological layers. It is demonstrated that the analyses based on the storage and linear flow regimes can be integrated into one analysis in order to reduce error bounds.
The method is applied to a number of examples in a water-flood offshore Sakhalin. Here, start-up of injection wells was accompanied by regular IFO testing in order to monitor fracture growth over time. The interpreted fracture dimensions were compared with predicted dimensions using a recently developed in-house waterflood fracture simulator. The fracture lengths as interpreted from IFO test analysis appeared to be systematically lower than the predicted ones, and a number of explanations for this difference are presented in the paper.
Application of the Fused Fault Block Technique to Fault Network Modeling
Authors: Hoffman Karen S. , Neave John W. , Nilsen Erik H. , Sarkisov Gennady 
Published: December 2007

Abstract
Fault network modeling of complexly faulted structures – those containing hundreds or thousands of faults – can be an extremely difficult and time-consuming process. A variety of methods exist to create the appropriate relationships between the faults, due to truncations, crossing, or offsets due to younger episodes of faulting, but each has limitations. Pillar or node-based techniques are often based on the concept that faults only exist where there are interpreted data; extensions of faults to intersections with other faults and/or truncation of erroneously crossing faults is a manual process, requiring the addition of nodes or pillars to the truncating surface. The location of the intersections can be dictated by the orientation of the pillars of the two faults, and so may not reflect the correct structure. An automatically generated binary tree, or hierarchy, can generate a reproducible fault network, where fault relationships can be stored. However, a binary tree cannot correctly handle all types of fault relationships and has particular difficulty in easily representing crossing faults.
Our technique uses a new concept of "fused" fault blocks. It begins with an approach somewhat similar to a binary tree, where each fault defines a hanging wall and foot wall side. However, our technique does not require faults that have an implicit relationship (that is, faults which do not intersect) to be explicitly defined in a tree. Fault intersections are determined from the active areas of the faults. Unlike a strict binary tree, fault relationships here can be modified at any time, as interpretation or data changes.
Truncations can be stored and re-used, making the fault network repeatable. The accuracy of the fault network, the flexibility of modeling, and the use of this network to create reservoir grids allows an entire asset team to work with a high-quality earth model.
Reducing Screenouts in High Permeability Formations, Novogodnee Field (Western Siberia)
Authors: Davidson B. M. , Faizullin I. , Kazykhanova N. , Gayfullin A. , Senchenko D. 
Published: December 2007

Abstract
The evolution of the fracture stimulation in the Novogodnee Field in Western Siberia is detailed in this paper. The target interval is the JV1 interval of the Jurassic formation. This is a highly productive interval producing at a typical pre-stimulation rate of approximately 70 ton/day (500 bbl/day) with a high volume of gas. Significant increases in the production rate can be achieved by the successful application of fracture stimulation. Unfortunately, this was not the initial case in the field because most of the fracture treatments screened-out early in the fracturing process.
Even though the initial fracture treatments did not achieve the designs results, they did yield important information. First, there were increases in production resulting from the fracture treatments, indicating there is significant potential of higher production from successfully performing fracture stimulation. Also diagnostic injections were performed prior to the main fracture treatment to measure the critical fracture parameters.
Therefore a project was initiated to perform a detailed analysis of these fracture treatments to understand the cause of the early screenouts. As a result of this study the fracture treatments were redesigned leading to successful completion of the fracture treatments. The proppant volumes successfully placed have been as high as 213 tons (470000 lbs) of proppant. This is a significant increase over the initial treatments that screened-out with an average proppant volume of36 tons (80000 lbs).
The resulting production increase from the successful treatments has been significant. The folds of increase in productivity have increased from 1.9 on the fracture treatments with the early screen-outs to an average on 3.1 folds of increase on the recent wells. The highest productivity increase was 3.4. These folds of increased productivity have resulted is the equivalent post-stimulation production rates increasing from 130 tons/day (950 bbl/day) to 220 tons/day (1600 bbl/day). Well J is an injection well as part of the pressure maintenance program. Following the fracture treatment the injection rate of fluid volume is equivalent to 1000 tons/day (7300 bbl/day). If the interval had not been fracture stimulated the rate would have been significantly less.