bluuebunny/crossref_metadata_2025_split huggingface dataset:
High-rate Gas Well Completions in Egypt’s Mediterranean Sea: Tao Field Development Strategy and Case Histories
Authors: Mekawy Ashraf , Rodet Vincent F. , Mered Reza , Gomez Ricardo A. , Parlar Mehmet 
Published: February 2010

Abstract
TAO field is a high rate gas development in the Mediterranean Sea, operated by North Sinai Petroleum Company (NOSPCO), a joint venture of Perenco and EGPC. The field comprises multichannel sandstone reservoirs from the Nile Delta depositional environment. Earlier exploration and appraisal stages had proven reserves for three of the six sands, with the remaining three identified as potential (unconfirmed) gas bearing reservoirs, all of which require sand control.
A multidisciplinary project team put forward and implemented a field development plan to maximize profitability through effective measures for overall cost reduction, while ensuring sustained delivery of the production commitment. This paper will detail the field development plan, implementation and results, along with the case histories. This plan included:Batch drilling and batch completion to minimize drilling and completion costs, and maximize data gathering as early as possible.Completing two of the four wells as openhole gravel packs targeting the most prolific sand to ensure that the production target is met with the productivity benefit of an openhole completion and reliability of gravel packing as a sand control technique.Completing the remaining two wells as cased hole gravel packs in squeeze mode to increase well productivity by ensuring maximum amount of gravel behind casing and targeting the two remaining sands with proven reserves as well as the sands with potential reserves in order to sustain the production commitment over project life, while avoiding to drill two dedicated appraisal wells.
All gravel packs were performed with filtered seawater as the base brine and mesh type sand control screens, with the exception of one of the zones, where alternate path screens were used in conjunction with a seawater compatible viscoelastic surfactant carrier fluid. Openhole gravel packs utilized a service tool that allowed post-gravel-pack filtercake cleanup treatment.
Post completion multi-rate tests concluded that both openhole gravel pack wells fulfilled the required productivity, showing potential productivity above 110 MMSFCD per well. In addition, the two of the zones tested in each of the cased-hole gravel packs showed potential productivity above 50 MMSCFD per zone.
Design Flaws in Hydraulic Fracturing
Authors: Economides M. J. , Wang X. 
Published: February 2010

Abstract
There are many widely held and often repeated misconceptions in the design of hydraulic fracture treatment. These include the design for fracture conductivity, fracture length (for which some have used terms such as "effective" or "apparent"), time of injection, and proppant injection schedule. These issues are intimately connected with the selection of proppants, fracturing fluids, and of course, the hardware for field execution.
For those practitioners who have adopted Unified Fracture Design (UFD), the desired fracture geometry is not a matter of speculation. For the given reservoir permeability, drainage, and, volume of specific proppant injected, the fracture geometry is set. A design that follows UFD will maximize the post treatment productivity index. Thus, statements like "maximizing conductivity" or "maximizing effective length" are not appropriate and in fact, they are meaningless.
However, there is a lot of room for improvement in design. These include the selection of a large mass of proppant or changing the proppant or using non-damaging fluids which, in this context, means damaging in the proppant pack or damaging to the formation by leak-off.
We present in this paper a wide range of designs for three oil and three gas reservoirs with permeability of 0.01, 1 and 100 md, respectively. Results show the impact on the productivity index by 1) deviating from UFD design, 2) the beneficial effects of lack thereof using more of better proppant, and 3) the effect of fluid selection and their leak-off, and the resulting different kind of damage. We show which kind of damage is important and which is unimportant. We also examine the impact of the proppant injection schedule for both unrestricted and tip screen out (TSO) treatments.
In the low permeability reservoirs, the selection of fluids and proppant schedule become crucial in obtaining the required fracture length. Fast ramping up of proppant is never indicated. Furthermore, leak-off damage is not important. For the high permeability reservoirs, selection of better proppants and fast ramping up of their injection are keys to the design. For the high permeability gas well, it is necessary to remedy the turbulence effects by changing the design further.
A Combined Laboratory and Field Approach to Optimize Scale Inhibition Placement Via Fracturing in Krasnoleninskoe Field, Russia
Authors: Yakimov S. , Mukhametshin M. , Sosenko O. , Sadykov A. , Levanyuk O. , Oparin M. , Gromakovsky D. , Mullen K. , Lungwitz B. , Fu D. , Mauth K. 
Published: February 2010

Abstract
Scale formation and accumulation is a major concern for Russian production companies. In Western Siberia, most wells produce fluids via Electric Submersible Pumps (ESP), and it is believed that up to 30% of the ESP failures result from scale damage. Despite that scaling is commonly first recognized at the ESPs, it can ultimately affect the whole production system. The most efficient treatment strategy to prevent scale induced damage in the tubular, including ESP, is scale inhibition. Traditionally, this involves an inhibitor squeeze treatment which is a localized inhibitor placement covering the near-wellbore area or the continuous injection of the inhibitor via a capillary tube. However, these techniques are designed to protect the production system. Squeeze treatments in hydraulically fractured formations are not always effective. Scale inhibitors together with compatible borate fracturing fluids can be used for a more effective scale inhibitor placement throughout the created hydraulic fracture to prevent scale formation from the reservoir level to the production system. This technique combines hydraulic fracturing and scale inhibition into one treatment resulting in operational simplicity. Since 2008, the combined fracturing/scale treatments have been successfully applied in the Krasnoleninskoe oil field in Western Siberia. This paper outlines the learning procedure and presents designs, testing and monitoring results from the campaign conducted at Krasnoleninskoe oil field (including Talinskaya and Em-Egovskaya sections).
Surfactant Nanotechnology Offers New Method for Removing Oil-Based Mud Residue to Achieve Fast, Effective Wellbore Cleaning and Remediation
Authors: van Zanten Ryan , Ezzat Dodie 
Published: February 2010

Abstract
Removal of oil-based drilling fluid (OBM) residue from the wellbore is critical to help prevent costly contamination of clear completion brines. Completion brine contaminated with OBM can adversely affect reservoir producibility. OBM residue may be present as a thin film that coats the casing or as part of the filter cake deposited on the formation. If left in place the oil can contaminate completion brines, cause excessive skin or even create emulsion blockages and formation damage. The best practice is to remove all OBM residue and water wet the casing and reservoir rock. Then clean brines can be maintained, proper zonal isolation through more effective cement bonds can be achieved and skin damage or emulsion blockage can be minimized.
Currently, OBM residue is removed from the wellbore by a series of solvent and surfactant treatments. These treatments result in large disposal volumes of solvents and generally incomplete water wetting of the casing or formation by the surfactant. Eliminating the use of solvents and using only surfactants to effectively remove OBM residue provides a more environmentally-friendly outcome.
A new method for removing OBM residue and water wetting surfaces relies on surfactant nanotechnology in high-density brine to form a micro-emulsion upon contact with oil. OBM filter cake with an acid-degradable weighting agent can also be removed and the reservoir becomes water wet if the surfactant is used in conjunction with an acid precursor. Micro-emulsion technology is also ideal for remediating formation damage by removing emulsion blockages and re-water wetting the reservoir.
This paper presents laboratory data generated during simulated casing cleaning and filter cake degradation experiments. Cleaning efficiency, permeability and wettability studies were performed showing the versatility of micro-emulsion technologies. The paper also presents and discusses field data from completion fluid displacements, cement pre-flushes and filter cake removal operations.
LCM Plugging Effect on Producing Formations During Drilling Naturally Fractured Sandstone Reservoirs
Authors: Restrepo A. , Osorio G. , Lopera S. H. , Hernandez J. , Duarte J. E. 
Published: February 2010

Abstract
Naturally fractured sandstone reservoirs are susceptible to drilling mud damage both at the fracture and matrix level. This problem becomes especially severe as reservoir pressure depletes due to: (i) the loss of backpressure preventing static and dynamic mud losses and; (ii) loss of energy for well clean up. Although several completion practices are covered by the experimental techniques described, of special interest in this study is cemented and perforated liners which can have some particular constraints if not properly designed and executed when drilling and completing mature naturally fractured sandstone reservoirs.
While drilling, the overbalance pressure exerted by the drilling mud on producing formations is a means for avoiding wellbore stability problems. When the reservoir pressure is close to its initial value, the near-wellbore region affected by mud losses and invasion is normally restricted to a few inches. Additionally, the reservoir often has enough energy to overcome filtrate damage within the rock matrix and inside natural fractures. This condition changes as reservoir becomes depleted, as a higher drilling overbalance occurs for the same mud weight, and reservoir energy for subsequent well clean-up is reduced.
The following study presents an experimental evaluation of synthetic oil-based mud (SOBM) drilling damage on naturally fractured reservoir cores. Two conditions were simulated: first, a condition in which mud invasion takes place into open natural fractures, followed by simulated under-balanced perforating and post draw-down stimulation. A second scenario is then considered in which simulates mud invasion into open fractures, but which is then followed by on-balance perforating and stimulation, and only after this is a draw-down imposed on the sample.
Results from the study indicate that very high levels of formation damage are caused when natural fractures get plugged and/or closed-over by mud filter-cake and lost circulation material (LNM) solids. Fluid pressure drawdown in the near-wellbore region and induced fracture closure pressures can, in the field, essentially create a compacted "new rock", with very low permeability and very high tensile stress. In this particular case study, this last condition is evident in the very low injectivity of the stimulation fluid and the very low value of regained permeability. When natural fractures are stimulated before imposing a drawdown, very good return permeability is achieved with an even higher value after closing fractures and re-stimulating.
Model, Measure, and Optimize Fluid Placement in Formations With Reservoir Pressure Heterogeneities
Authors: Glasbergen G. , Yeager V. 
Published: February 2010

Abstract
In matrix stimulation and injection treatments for removing or preventing formation damage, correct placement of the injected fluids is essential. Throughout the years, several diversion and placement techniques have been applied to obtain a desired fluid placement. These techniques are needed to overcome natural or artificially created heterogeneities. One of these heterogeneities is reservoir pressure. When barriers between the formation layers exist, the layers can have significant pressure depletion caused by production or can be overpressurized because of water flooding. To treat the layers with elevated reservoir pressures is challenging; however, they are often the target areas of a treatment. Another challenge is that during the shut-in period following the treatment, crossflow in the wellbore can be expected, which can cause undesired fluid movement.
To understand and quantify the challenges related to pressure heterogeneities, the fluid placement and crossflow in the wellbore for treatments in formations with pressure heterogeneities have been modeled. A fluid-placement simulator that has the ability to include heterogeneities in pressure was used. In addition, the effect of fluid placement with the use of distributed temperature surveys (DTS) and single-point bottomhole pressure were measured. The advanced measurement techniques were used to both monitor the placement of the fluids during the treatment and identify the crossflow in the wellbore after the treatment was finished.
These measurements provided fascinating results and provided the insight that, in about 50% of the monitored wells, crossflow could be identified up to flow rates that exceeded 1 bbl/min. In addition, the pore pressure in the high-pressure zones could be determined by measuring the wellbore pressures when the crossflow started.
This paper discusses several case histories where the fluid placement during the treatment and the post-treatment shut-in were measured and modeled. Furthermore, techniques that can be used to optimize the fluid placement in formations with significant reservoir-pressure heterogeneities and which techniques are less useful are discussed.
Microemulsion-Assisted Fluid Recovery and Improved Permeability to Gas in Shale Formations
Authors: Zelenev Andrei S. , Zhou Hui , Ellena Linda B. , Penny Glenn S. 
Published: February 2010

Abstract
Hydraulic fracturing of shale formations presents a well-known challenge due to high entrapment of frac fluids. Typical levels of fluid recovery from shale formations are on the order of 30% or lower. Fluid loss into shale produces liquid blocks that interfere with the gas flow in already tight formations. Friction reducers or other additives present in fluids can cause further formation damage. Search for technologies that would maximize gas flow rate and yield high recoveries is ongoing. In recent years microemulsions have been successfully used for remediating damaged wells and enhancing production from tight gas formations. In the present work we have explored the use of such additives for improving fluid recoveries from columns packed with shale/sand mixtures and for improving permeability of split shale cores to gas.
Evaluation of a New Environmentally Friendly Chelating Agent for High-Temperature Applications
Authors: Mahmoud M. A. , Nasr-El-Din H. A. , De Wolf C. A. , LePage J. N. , Bemelaar J. H. 
Published: February 2010

Abstract
Matrix acidizing is used in carbonate formations to create wormholes that connect the formation to the wellbore. Hydrochloric acid, organic acids, or mixtures of these acids are typically used in matrix acidizing treatments of carbonate reservoirs. However, the use of these acids in deep wells has some major drawbacks including high and uncontrolled reaction rate and corrosion to well tubulars, especially those made of chrome-based tubulars (Cr-13 and duplex steel), and these problems become severe at high temperatures. To overcome problems associated with strong acids, chelating agents were introduced and used in the field. However, major concerns with most of these chemicals are their limited dissolving power and negative environmental impact.
Glutamic acid diacetic acid (GLDA) a newly developed environmentally friendly chelate was examined as a replacement for acid treatments in deep oil and gas wells. The solubility of calcium carbonate in the new chelate was measured over a wide range of parameters. Core flood tests were conducted using long Indiana limestone cores 1.5-inch in diameter and 20 inches in length, which allowed us to better understand the propagation of this chemical in carbonate rocks. The cores were scanned with X-ray before and after the injection of chelate solutions into the cores. The concentration of calcium and chelate were measured in the core effluent. To the best of our knowledge, this is the first study to examine the fate and propagation of chelating agents in coreflood studies.
GLDA has a very good ability to dissolve calcium from carbonate rocks over a wide pH range by a combination of acid dissolution and chelation. The addition of 5 wt% sodium chloride did not affect the GLDA performance at pH= 13, but significantly accelerated the reaction at pH= 1.7. Compared to other chelating agents, GLDA dissolved more calcium than EDG but less than HEDTA at high pH values. GLDA of pH = 1.7 was able to form wormholes at 2 and 3 cm3/min. GLDA was found to be thermally stable at temperatures up to 350°F
A New Acid Fracture Conductivity Model Based on the Spatial Distributions of Formation Properties
Authors: Mou Jianye , Zhu D. , Hill A. D. 
Published: February 2010

AbstractThe success of acid fracturing depends on uneven etching along the fracture surfaces caused by heterogeneities such as variations in local mineralogy and variations in leakoff behavior. Acid fracture conductivity, created only if less dissolved parts act like pillars to keep the fracture open under closure stress, depends on the spatial distribution of fracture roughness, which is determined by the spatial distribution of formation properties such as permeability and mineralogy distributions. Existing laboratory experiment-based acid fracture conductivity correlations are for random roughness distributions, that is, they do not consider the effect of channels on conductivity. Channels provide greater conductivity at low closure stress and lasting conductivity after fracture closure, and occur on a scale that is neither used in laboratory measurements of acid fracture conductivity which use core samples that are too small to observe such a feature, nor in typical acid fracture simulations, in which the grid block size is much larger than the scale of local heterogeneities.In this study, an extensive numerical study was done using an intermediate-scale acid fracture model with total dimensions comparable to a grid block size in acid fracturing simulators and grid sizes comparable to core sample sizes in laboratory acid fracture conductivity experiments. An acid fracture conductivity correlation consists of two parts: conductivity at zero closure stress and the rate of conductivity change with closure stress. This study focuses on the first part. With the model, by analyzing the relationship among fracture surface etching patterns, conductivities, and the spatial distributions of permeability and mineralogy, we developed acid fracture conductivity correlations as functions of statistical parameters of mineralogy and permeability distributions on the fracture surfaces. The new correlations consider the contribution of channels, which can be created by acids if the formation is heterogeneous in either permeability or mineralogy, or both. In these correlations, the acid fracture conductivities depend strongly on statistical properties of the permeability and mineralogy distributions, namely the standard deviations, and the horizontal and vertical correlation lengths of these distributions.
The Next Generation of Regenerative Catalytic Breakers for Use in Alkaline and High-Temperature Fracturing Fluids
Authors: Armstrong C. D. , Stevens R. F. , Le H. , Stephenson C. , Qu Q. 
Published: February 2010

Abstract
Enzymes represent an attractive alternative to oxidative chemical breakers for several reasons. They are polymer specific, environmentally friendly, easy to handle, miscible, do not damage equipment and they are naturally regenerating catalytic breakers. Enzymes have been used with great success for many years as breakers in fracturing applications. However, traditional enzyme breakers derived from mesophilic sources have a tendency to unfold from their functional three-dimensional conformation into an inactive form under high temperatures. Thermal unfolding of enzymes proceeds via a dynamic equilibrium between active and inactive states, which reduces the enzyme activity, prior to an irreversible unfolding step as the temperature increases.
To maximize enzyme functionality, a new generation of polymer-specific, thermostable enzyme was developed. The gene coding for the new enzyme was obtained and codon optimized for production in a commercially available expression system. Additional genetic enhancements were made to increase the yield and stability of the enzyme and further lower production costs.
An Experimental Approach To Investigate Permeability Alteration Caused by Underbalanced Drilling in Oil Reservoirs
Authors: Moghadasi J , Kakavandi M. , Kordestany A. 
Published: February 2010

Abstract
The most prominent factor in using UBD is to eliminate or minimize formation damage provided that underbalanced condition maintained 100% of the time during drilling operation. However, during a UBD operation, it is difficult to guarantee that the drilling fluid pressure is always maintained in underbalanced condition.
A series of dynamic filtration and return permeability tests have been conducted using reservoir sensitivity core flood apparatus to investigate the permeability alteration due to transition of UBD condition to overbalance one during UBD operation.
The results evinced significant permeability reduction when diesel was used as a drilling fluid without any extra additives, due to lack of mud cake and consequently invasion of fine particles existing in the diesel used as drilling fluid for UBD operation into the core samples. Results were plotted in terms of permeability versus diesel volume lost into the formation per square inch of wellbore wall and a linear pattern was found for permeability reduction.
So, better plan of UBD operations is necessary for the industry to avoid undesired permeability reductions and it is crucial to develop ways to have an underbalanced condition all the time while drilling and to use filtered diesel or diesel with low solid particle content as a UBD drilling fluid, knowing that usually we do not use loss control materials in UBD drilling fluids. In addition, completion should be planned to be conducted without exposing the formation to overbalanced pressure.