bluuebunny/crossref_metadata_2025 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

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

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

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

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

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

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

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

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

The 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

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

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.
Successful Water-Shutoff Case Histories in a Naturally Fractured Carbonate Reservoir in Offshore Mexico Using an Organically Crosslinked Polymer System With a Modified Tail-In
Authors: Hernandez R. , Vasquez J. , Cancino V. , Soriano E.
Published: February 2010

This paper presents the laboratory development and successful field implementation of an organically crosslinked polymer (OCP) system for water- and gas-shutoff applications. An overview of case histories in a naturally fractured carbonate reservoir (with BHT >250°F) in offshore Mexico where the OCP was successfully applied to reduce water production is presented. To control overdisplacement of the treatment, a modified tail-in combining the OCP system with inert particles was used to provide leakoff control, resulting in a controlled placement of the sealant.

The OCP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). To date, more than 600 jobs have been performed with the OCP system around the world to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel-pack isolation, fracture shutoff, and/or casing-leak repair. The development results of this OCP system are discussed regarding its activation time and its effectiveness to limit permeability to water and provide thermal stability in sandpack flow tests at elevated temperatures. Lastly, the combination of the OCP system with inert particulates to provide fluid-loss control is discussed.

The OCP system has been successfully applied to sandstone, carbonate, and shale formations in need of conformance treatments. This system has been successfully tested to withstand a differential pressure of at least 2,500 psi and is resistant to acid, CO2, and H2S environments. Because of the ability of the OCP system to withstand pressure, workover operations have been successfully performed in previously treated wells including acid-stimulation, sand-control, and frac-packs treatments, among others. An overview of case histories in which the OCP system was used in offshore Mexico is presented. This advanced water-control technology has extended the well life and profitability of the treated wells. In the past, many of these wells were abandoned because of the limited water-handling facilities.
Dynamic Scaling Evaluation in Gravel Packs Using Low-Sulphate Seawater
Authors: Shields R. , Bourne H. , Vazquez O. , Sorbie K. , Singleton M.
Published: February 2010

In fields where it is unattractive to control barite scaling through chemical intervention (e.g. scale inhibitor squeeze treatments), one option is to substitute the injection of seawater with low-sulphate seawater (LSSW) for pressure maintenance. Injecting LSSW minimises the operational risk of barite deposition on injection water breakthrough. The specification for the LSSW sulphate ion concentration dictates the design of the Sulphate Removal Plant (SRP) required and may influence the field development strategy. There is the possibility that barite deposition can occur within gravel packs designed to minimise sand production. It is in these that the potential for scaling was investigated.

Dynamic scaling runs were performed in laboratory scale gravel packs using a mixture of a Formation Water (FW) and LSSW. The initial design involved varying the total flow rates and mixing ratio of the brines in order to produce a 'safe envelope' (Ba2+/SO42- composition) that could be used in the field. The experimental procedure was developed to examine the steady-state effluent profiles and to use these to derive the rate constant, k, for barite deposition. This could then be used in a computer model to predict scaling quantities and timescales.

Under 'true' LSSW conditions (20ppm sulphate) the steady-state effluent results proved difficult to interpret due to the limits of accuracy. The sulphate levels were then varied in order to increase the level of accuracy, with the hypothesis that, for a given set of conditions (temperature and pressure), the rate "constant" should remain the same for any Saturation Ratio (SR).

Upon closer inspection of the derived rate constants, it was discovered that they were not constant but were directly proportional to the SR for the different input concentrations. Plotting the rate constants against SR showed a linear relationship between the two variables. This was confirmed by using sulphate and barium levels that were unrelated to the previous series of tests.

The experimental procedure and the resulting model being developed from the work reported in this paper will assist in designing operational procedures to minimise rate related scaling in gravel packs in fields where squeezing is undesirable.
A New Method of Grain Size Determination for Sand-Control Completion Applications
Authors: Chen J. , Chen S. , Altunbay M. M. , Tyurin E.
Published: February 2010

Grain size distribution of formation sands is one of the crucial parameters in a sand control program. Such information is commonly derived from sieve or laser particle size analysis (LPSA) techniques on a limited number of core samples from the target well or from a neighboring well in the same field. These laboratory-based grain size analysis methods require proper disaggregation of grains, a process which often causes breakup of some grains resulting in distortion in the grain size distribution. Moreover, variations of grain sizes in the formation may not be captured by the limited number of core samples.

This paper presents a new method of grain size determination from nuclear magnetic resonance (NMR) logs using micro-structural rock modeling (MSRM). NMR probes the pore space as the relaxation time distribution of the wetting-phase fluid correlates to pore size distribution while the non-wetting phase fluid carries no pore size information. To derive grain size distribution from NMR relaxation time measurements, MSRM is applied to reconstruct the pore/grain distribution and to simulate NMR responses by considering mineralogy, partial water saturation, surface relaxivity, and the surface roughness factor of the grains. Extensive core studies were performed to validate this method. A ternary diagram is developed to correlate surface relaxivity and the surface roughness factor with the amount of quartz, feldspar, and clay as a triangle in the ternary diagram.

Field application case examples are presented. Continuous grain size distributions are calculated on foot-by-foot basis that capture the variations of grain size in the formation sands along the depth. The log-derived grain size distribution shows good agreement with the core data at depths where core samples are available. D50 and D90 characteristics are derived from the continuous grain size distributions to assist the completion decisions, e.g., the selection of screen mesh size in the openhole standalone screen sand-control approach, or the selection of gravel size in the gravel-packing sand-control approach.
Two-Dimensional Analytical Solution of Ideal Perforation Flow
Authors: Li B. , Sun D. , Gladkikh M. , Wu J.
Published: February 2010

Core flow efficiency (CFE) is defined to quantitatively evaluate the flow performance of single-shot perforation. To calculate CFE, the flow rate of the ideal perforation flow in the core target is needed. The ideal flow rate is typically calculated with numerical simulators, but the computation may be time-consuming and costly.

This paper presents the two-dimensional analytical solution of the steady state flow model (mass conservation equation) for the ideal single-shot perforation in a cylindrical core sample. The separation of variable method is used to solve the partial differential equation of the flow model. Pressure and velocity distributions in (r, z) space are obtained, as well as the flow rate distribution along the perforation tunnel.

The accuracy and convergence of the analytical solution for the ideal single-shot perforation flow are investigated and compared with those of the numerical solution of the commercial software ANSYS FLUENT. The analytical solution for the governing equation of the ideal perforation flow is composed of the infinite number of Bessel functions. To compute the CFE by making use of this analytical solution, the analytical solution is approximated with a limited number of Bessel functions. The approximated analytical solution is analyzed and compared with the numerical solutions from ANSYS FLUENT.

Further, the axial, radial, and radial-axial flow geometries of the ideal shingle-shot perforation are characterized with their approximated analytical solutions. Interactions between the boundary condition, perforation parameters, and core parameters are investigated for these flow geometries.

The analysis results show that: 1) the analytical solution has no grid effects; 2) the boundary condition of the perforated core is the dominant factor to the ideal flow rate of the perforated core; 3) the penetration depth and anisotropic permeability are the significant factors to the flow performance of the perforated core.
Development and Field Applications of an Aqueous-Based Consolidation System for Proppant Remedial Treatments
Authors: Villesca J. , Loboguerrero S. , Gracia J. , Hansford A. , Nguyen P. D. , Rickman R. D. , Dusterhoft R. G.
Published: February 2010

Proppant produced during production often causes damage to downhole pumps and surface equipment. In addition to restricting production rate, frequent workovers are often required to remove proppant or sand infill, thus resulting in costly downtime. To help resolve these proppant production problems, solvent-based curable resins have often been used in remedial treatments of affected wells. These resin systems have been applied in intervals of less than 100 ft. For longer intervals, ineffective diversion of solvent-based resins and their potential interaction with water in the wellbore can prevent them from providing complete coverage over the entire perforated interval.

A novel water-based consolidation system has been successfully developed to overcome safety, fluid compatibility, and placement issues, which most current solvent-based resins encounter during their field applications. This paper presents the results of laboratory testing and field applications and discusses the challenges, lessons learned, treatment procedures, and recommendations in applying this newly developed resin system.

The curable consolidation component is emulsified to form a water-external emulsion so that the active material can be delivered in a brine-based solution. Extensive laboratory testing has indicated that optimum concentration of coating is necessary to maximize the bonding between proppant grains. This allows the proppant pack to withstand high production flow rates and to overcome the effects of stress cycling while minimizing any reduction in its permeability. Results from field trials showed that this aqueous-based consolidation system successfully treated both proppant and formation sand in near-wellbore regions to lock them in place without damaging production flow paths. In these field tests, intervals in excess of 300 ft were treated effectively with a bullhead squeeze using consolidation-treatment fluids that were foamed to a quality of 50 or higher to aid in diverting treatment fluids and extending treatment volume.

One major advantage of this aqueous-based system is its simplicity in field treatments without the concern of fluid incompatibility between fluid stages during their placement because of its benign behavior. The new system uses small treatment volumes to impart excellent consolidation properties while, at the same time, retaining formation permeability. This makes the treatment system simple to deploy and economically viable.
Laboratory Investigation of Brine Diffusion Through Oil-Based Mud Filter Cakes
Authors: Berntsen A. N. , Robbes A.-S. , Cerasi P. R. , van der Zwaag C. H.
Published: February 2010

When gravel packing wells in brine after an oil-based drill-in, filter cake strength and permeability are important factors for successful operations. These relate to controlling fluid losses, firstly, by resisting mechanical wear when running production screens and, secondly, by providing a tight hydraulic seal when pumping gravel.

Two oil-based mud formulations with "initial" and "depleted" bridging packages, respectively, and otherwise equal formulation, were used to deposit filter cakes on outcrop sandstone plugs in a Hassler-type core holder. Drilling mud was then displaced by gravel pack carrier brine keeping an overbalance pressure. Brine was allowed to permeate through the oil-based filter cake. The filter cakes before and after exposure to brine were compared in terms of cake strength, and volume of brine produced through.

It was found that brine transport through the filter cakes at the same overbalance pressure was slower than the static mud filtration rate. Scratch tests showed a higher strength for the filter cake formed with the "initial" particle size distribution, and that both filter cakes strengthened significantly following brine diffusion. NMR T2 distributions and 1D NMR intensity profiles showed that core plugs exposed to the mud formulation with "depleted" bridging package experienced stronger alterations in NMR properties and deeper damage than the formulation with the "initial" bridging package.

The methods used in this study have shown to have the potential of probing some of the mechanical and hydraulic properties of filter cakes and the extent to which core plugs are invaded by mud particles during filtration and filter cake buildup. Future work will address the effect of different base fluids, water-based or oil-based, and of different bridging packages to improve our understanding of how the fluid basis affects filter cake qualities. Other options are to look at the effect of wash pills on filter cake properties.
A Theoretical and Experimental Analysis of Dynamic Filtration in Drilling Operations
Authors: Scheid C. M. , Calcada L. A. , Araujo C. A. , Waldmann A. T. , Martins A. L.
Published: February 2010

This paper describes a numerical filtration model validated by data obtained from an experimental dynamic filtration loop. The model predicts the filtercake buildup and filtrate flow rate in the drilling process using non-Newtonian muds. It is also able to calculate filtercake properties like permeability and thickness. The equations, written in cylindrical coordinate, are based on the motion and mass conservation equation of the fluid described by Darcy's law. In addition, the permeability and porosity are correlated to the filtercake pressure. The point at which the mud fluid shear rate and the filtercake shear strength are equal defines the filtercake thickness.

In the dynamic filtration loop there is a tube with a permeable wall where the carbonate suspension of different sized particles is filtrated. The suspension is homogenized in a tank mixer and pumped using a positive displacement pump. The filtration model was validated through experimental data. In this paper, we discuss the effects of cross-flow velocity and filtration pressure on the filtrate rate and filtercake buildup. The simulated data of filtrate rate and filtercake thickness agreed well with the experimental data.
Improved Selection Criteria for Sand Control - When Are "Fines" Fines?
Authors: Byrne Michael , Slayter Adrian , McCurdy Philip
Published: February 2010

When sand control is required in production or injection wells, one of the key design criteria is that the sand control should allow those "fines" present to pass, whilst retaining "sand". However the definition of "fines" is not universal and some arbitrary size and/or compositional definitions are often used that could potentially lead to inappropriate sand control design.

The fines in any rock sample are usually categorized as that portion of the rock which passes through a ~45 micron sieve. This is a convenient cut-off point for laboratory evaluations as it represents the finest commonly used sieve. It has become routine to use the percentage of fines in a rock sample as one of the key parameters for sand control type selection and specific screen selection. In a coarse-grained, well-sorted sand, particles "less than ~45 microns" may well represent that part of the rock that can move through the pore throats. However, significant variation exists in oil and gas reservoirs and this should be considered in order to obtain an appropriate definition of what constitute fines for a specific reservoir. From a reservoir perspective, the preferred definition of "fines" is that part of the rock that can move through the pores of the intact rock.

Using pore throat size measurements and estimates, it is possible to develop a much more rigorous mobile fines size for any formation. Coupled with grain size analysis (which should include some laser analysis of the finer fraction) the true "fines" can be quantified for any given sand. The sand control selection is made using this new definition of fines, leading to optimum and tailored selection, based on science rather than convenience or tradition. For sand control performance evaluation it is not only the mobile reservoir fines that are a concern. Should the formation fail into an annulus then the rock components may re-sort in the annulus and bring about high skins and possible screen plugging. Here, the sizing of the fines that are of concern will be different.

It has been convenient to adhere to somewhat arbitrary particle size distribution cut-off points when selecting sand control. When informed with an improved understanding of the petrology, particle behaviour, impact of their movement, and the interaction between the formation and the well, while it is being both constructed and produced it is proposed that we can improve the selection process.
Propagation and Retention of Viscoelastic Surfactants Following Matrix Acidizing Treatments in Carbonate Cores
Authors: Yu M. , Mahmoud M. A. , Nasr-El-Din H. A.
Published: February 2010

Viscoelastic surfactants have been applied extensively in the field, because of their unique characteristics of forming rod-like micelles with the increase of pH and calcium concentration. There is continuous debate in the industry on whether the gel generated by these surfactants causes formation damage or not. This is especially true in dry gas wells. The objective of the present study is to conduct core flood experiments using surfactant-based acids and measure the concentration of the surfactant concentration in the core effluent. Material balance on the surfactant will shed lights on the amount of surfactant recovered, which will help in assessing damage due to surfactant gel retention in the cores.

Core flood tests were performed using calcium carbonate cores 1.5 in. diameter and 20 in. length. The cores were injected with a surfactant-based acid of 15 wt% HCl that contained 7 vol% surfactant and other acid additives. Core flood test were conducted at constant injection flow rate that was varied from 3 to 40 cm3/min. Carbonate cores of various initial permeability were used. In all core tests, surfactant concentration was measured in the injected acid and core effluent using the two-phase titration method. Mutual solvent was used to break surfactant gels. Considerable amounts of viscoelastic surfactant were retained in the carbonate cores after the acid treatments, and the retained surfactant gel is a source of formation damage if not effectively removed. The amount of surfactant-based acid required to create wormhole in carbonate matrix is high at both low shear rate (< 900 s-1) and high shear rate (> 3,000 s-1), and is low at intermediate shear rates with the minimum value at shear rate of 1,500 to 2,000 s-1. The surfactant retention in the carbonate matrix is lowest at shear rates near 2,000 s-1, and is high at both high and low shear rates. Surfactant was retained in gelled form. Mutual solvent was able to remove as much as 21% of the total amount of surfactant injected into the core.
Enhancing Gas and Oil Production With Zeta Potential Altering System
Authors: Johnson D. , Schoppa D. , Garza J. , Zamora F. , Kakadjian S. , Fitzgerald E.
Published: February 2010

This paper describes laboratory studies and field results of a Zeta Potential Altering System (ZPAS) used in hydraulic fracturing treatments. Laboratory and field results show ZPAS minimizes proppant flow back, controls fines migration, enhances fluid load recovery, and inhibits calcium carbonate scale formation. This system, based on an inner salt, modifies the zeta potential of particles such as frac sand and formation substrate, changing the charge towards neutral values and therefore enhancing particle agglomeration. A variety of oil and gas formations can be treated by incorporating the new chemical additive into stimulation fluids. The chemical additive can be applied on the fly using several fluid systems to deliver the product. It is capable of treating proppants such as white and brown sand as well as ceramic proppants in any mesh size allowing flexibility in treatment design. A multi-well comparison of fractured wells, treated with ZPAS and of offset wells without the chemical, has been made in the Des Moines Granite Wash formation of the Texas Panhandle. In this study, results show wells treated with ZPAS had no significant proppant flowback compared to non-treated wells. In one case, a significant difference in production was observed from the ZPAS treated well compared to the untreated well.
Single-Trip Perforate and Frac-Pack Completion With High-Efficiency Frac Gel in Bonga Phase II
Authors: Janz H. , Ogunsina O. , Apena A. , Alawode O. , Bagal J. , Kouteu Y. , Mbiguis Y. , Bopda G.
Published: February 2010

The Bonga field is located offshore deepwater Nigeria. Part of the second phase of the development comprised five frac-pack treatments executed in a multi-darcy environment. With permeability variations from 1 to 7 Darcies, the salt-tolerant fracture fluid that was used for the frac treatments had efficiencies in the order of 40%, compared to 10 to 15% most commonly achieved in such treatments (Witteveld, 2004; Cipolla, 2005). Use of such a high-efficiency fluid resulted in substantial reduction in pump rates and horsepower requirements.

All five treatments were performed from a stimulation vessel, three of the treatments with the conventional two-trip technique and two using the single trip perforating and frac-packing technique. The single trip system allowed the completion time to be reduced by 1 to 2 days as compared with conventional system.

This paper discusses Bonga Phase 2 frac-pack treatments, with a comparison of the two techniques (single trip versus conventional) from a cost savings as well as well performance standpoints based on field applications. Design, execution and evaluation of the treatments are detailed, along with a discussion of the fluid system, and the lessons learned during the completions campaign.
Testing of a Fluid-Powered Turbo-Acoustic Source for Formation-Damage Remediation
Authors: Kolle J. J. , Theimer A. R.
Published: February 2010

Acoustic energy has the potential to stimulate wells by removing drilling and production damage from the formation near the wellbore, overcoming water block and breaking emulsions. All of these applications require high acoustic power and frequency. A fluid-powered turbo-acoustic source has been developed for operation on coiled tubing. This source generates a high-power, high-frequency resonant acoustic signal in the treatment fluid to ensure good acoustic coupling to the formation. The turbo-acoustic source incorporates a turbine, flow-splitter and resonant cavity to convert hydraulic power into an acoustic signal. A 1-11/16″ prototype generates 2 to 12 kW of acoustic power at 4 kHz. The source was used to recover permeability of sandstone that was damaged with guar gum in laboratory tests. Successful recovery of core permeability requires high-acoustic power levels and underbalanced flow conditions to flush the fines out. The turbo-acoustic source provides the ability to restore near-wellbore permeability using coiled tubing in a variety of well configurations. The tool can be operated with a gas separator for underbalanced operations in depleted wells.