bluuebunny/crossref_metadata_2025_split huggingface dataset:
Double-Emulsion Spacer Design for Highly Efficient Invert Emulsion Displacement
Authors: Lu S. , Foxenberg W. 
Published: June 2014

Abstract
The wellbore displacement is a necessary and critical step toward subsequent completion operations and production. A successful displacement process saves significant rig time, cuts disposal volume, reduces fluid contaminations and provides the best opportunity for a successful completion. Traditionally, a displacement train typically has multiple cleaning spacers, including a solvent spacer and a surfactant spacer. It is highly preferred to have a cleaning spacer to achieve the desired wellbore cleanliness as a single stage and with minimum circulation volume. Surfactants, solvents and emulsions are used in the cleaning spacer(s) for displacement of invert emulsion drilling fluids (IEF). The spacer system is selected depending on the displacement requirements and wellbore conditions. This paper describes innovative double–emulsion technology that shows highly efficient and effective performance in IEF displacement, as the design fully combines the power of both surfactants and solvents.
This paper presents theoretical and lab testing results for fundamental understanding of IEF film removal from metal surfaces under various conditions. It was found that the solvency and surfactancy play different roles during the film removal process. A macroemulsion or microemulsion contains both solvents and surfactants but they often have a limited operational window with reduced solvency and surfactancy. Based on the analysis described in this paper, an innovative double-emulsion system was developed to fully preserve the solvent cleaning power and dispersive and water–wetting power of surfactants. It has a unique water-in-oil-in-water structure, in which the dispersed solvent droplets contain smaller droplets of a second aqueous phase. The solvent droplets effectively remove the top layer of mud film and directly deliver the surfactants to the metal surface. This technology has been applied in various successful field applications.
A New Outlook on the Ideal Packing Theory for Bridging Solids
Authors: Chellappah K. , Aston M. 
Published: June 2014

Abstract
Carefully engineering the size distribution of bridging solids should enable us to form filter cakes of low permeability. A theory called the ideal packing theory is commonly used to blend bridging solids which suggests the ideal blend of particles should follow the relationship cum vol% ∝ dx. The aim of this work was to experimentally assess this theory. Investigations were carried out to determine if there is an x value which gives a better fluid loss performance than the typically-used x = 0.5.
The results suggest that selecting x ~ 1 could be more appropriate than using the conventional x = 0.5. The physical meaning when x = 1 is that there will be an equal volume of particles of each size within the distribution; i.e. the distribution is linear. In addition, the results also showed that a blend with a broad size distribution gave a lower fluid loss than a narrow distribution, even when the narrower distribution consisted of finer particles. The trend was that filter cakes of decreasing permeability were formed as x increased from 0.1 to 0.5. Further increase in x up to 1.25 did not appear to have a prominent effect, while further increases beyond 1.25 appeared to increase the filter cake permeability. Trends were similar for filter cakes formed on filter paper and on simulated rock material.
Particle blending is important for the selection of bridging solids for drill in fluids, and also for wellbore strengthening (stress cage) applications. Conventional ideal packing theory has been widely used but a review of this theory backed up by laboratory checks has been overdue. This work should aid in the development of a more consistent approach to the selection of the optimum blend of bridging material for a given application.
Compatibility and Phase Behavior Studies Between Corrosion Inhibitors and Surfactants-Based Acids
Authors: Li L. , Nasr-El-Din H.A. , Zhou J. , Holt S. 
Published: June 2014

Abstract
A good surfactant-based acid should have the following properties: thermal stability, compatibility with cations, low viscosity in live acids but high viscosity in spent acids, ease to be removed by internal or external breakers, and no harm to the environment. Corrosion inhibitors must be added to the acid system to protect well tubulars and minimize the Fe contamination. The components of corrosion inhibitor usually contain short-chain alcohols (e.g. isopropyl alcohol) that can significantly affect the properties of surfactant-based acids. Therefore, corrosion inhibitor plays an important role in evaluating acid systems.
Two amine oxide surfactants (S and SW) were examined in this work. The composition of the surfactants was similar, but there was more 1,2 propanediol in surfactant SW. Three corrosion inhibitors (A, B, and C) were tested and all of them contained a certain amount of propargyl alcohol. However, there was a larger amount of isopropanol in corrosion inhibitor A, and more butanol in corrosion inhibitor B. A HPHT rheometer was used to measure the rheological properties (viscosity, G’ and G") of surfactant-based water system, live and spent acids from 75 to 300oF at 300 psi.
The results show that the addition of corrosion inhibitor to spent acid significantly reduced its elastic (G’) and viscous modulus (G’’). The maximum temperature that these two surfactants can be used was 220°F. Compared to surfactant-based acids made with corrosion inhibitor B or C, the acids with corrosion inhibitor A showed a much higher viscosity, but phase separation was observed after heating to 300°F. Although corrosion inhibitor B was compatible with surfactants, it adversely influenced the rheological properties of acids. If corrosion inhibitor C was used, the system with surfactant SW can be effectively used at temperatures above 150oF; whereas acids prepared with S1 can be efficiently applied at lower temperatures (&lt;150°F). Cryo-TEM studies showed that corrosion inhibitors affected the rod-like micelle network, which caused the reduced apparent viscosity. Results of this work can be used to better select acid additives to maximize the performance of amine oxide-based acids.
Analysis of Parameters Affecting Critical Flow Rate in a Horizontal Well: Case Study in Ahwaz Oil Field
Authors: Goodarzian S. , Ghalambor A. , Izadi M. 
Published: June 2014

Abstract
Horizontal well is a solution to accomplish higher production in thin reservoirs or those with very low permeability. However, these wells suffer from early water and gas conning and this jeopardizes the life of the well and its productivity. Therefore, having an understanding of the conditions in which coning occurs is highly desired. In this study several rock and fluid properties which affect water or gas breakthrough will be investigated and a few correlations are proposed to determine the breakthrough time and critical flow rate for the well in question. Ahwaz oilfield is one of the giant fields in the world and the reserves are estimated at more than 40 billion barrels. The reservoir is extremely heterogeneous latterly and vertically. Reservoir studies indicate that horizontal drilling is the best solution to increase ultimate recovery. However, the water and gas coning is the main problem in this field and several reports have shown the severity of this issue. A simulator has been written in FORTRAN to investigate the sensitivity of various parameters on well productivity and water breakthrough.
The study shows that when the formation volume factor increases by 0.1 bbl/STB, the well productivity decreases by 2480 STB per day and also the water breakthrough time increases. In this paper it has also been shown that the reservoir under study with high permeability is not performing efficiently using horizontal wells since having high production in early times does not guarantee higher ultimate recovery.
The dominant parameters in this case study are the horizontal well length and completion type. Using ICD (Inflow Control Device) certainly decreases the water-oil front movement towards the wellbore, and finally according to the simulation if the well had been drilled 320 ft above the water-oil contact instead of 127 ft, the critical flow rate would have been increased from 34000 to 210000 barrel per day.
Coreflooding Experiments on the Combination of Water Shutoff and Acid Treatments in Carbonate Formations
Authors: Al-Anazi M. S. , Caliskan S. , Al-Yami I. S. 
Published: June 2014

Abstract
Water shutoff using polymer gels has been practiced with success for long time. However, in certain cases, there is a need to acidize a well while isolating part of it using a gel treatment especially in long horizontal wells. The application of combined treatment is challenging and has resulted in a mixed outcome. The acid reacts with carbonate around the gel destroying the benefits of the gel treatment. Likewise, the application of the gel post an acidizing treatment is ineffective. The objective of this paper is to investigate the effectiveness of combining water shut-off and acidizing in one treatment in carbonate formations.
Core-flood testing was conducted to investigate the effectiveness of water shut-off gels before and after acidizing the core plug. Two scenarios were examined; the first one included pumping a cross-linked organic polymer gel to a carbonate core plug then followed by emulsified acid. In the second scenario, the core plug was acidized then the gel treatment was pumped. The gelling system consisted of polymer and dual set of delayed organic crosslinkers. The acid was 20 wt% emulsified HCl. CT scanning images were obtained before and after each step. The testing was performed at 200°F and 500 psi pore pressure.
The core flood experiments showed that when acid was applied after the gel treatment wormholes were created and dissolved the rock around the gel. On other hand, when the gel was applied after the acid, the gel was not able to withstand the differential pressures and allowed the flow of water because of the inability of the gel to plug the wormholes. It was demonstrated that the gel and acid treatments must be isolated from each other by mechanical means or deeper penetration of the gel.
Design, Installation, and Performance of Big Bore (9-5/8 in.) Completions: Mari-B Field, Offshore Israel
Authors: Healy John , Sanford Jack , Reeves Donald , Dufrene Kerby , Haskell Peter , Luyster Mark , Bariudin Victor 
Published: June 2014

Abstract
A case history from Offshore Israel is presented that describes the successful delivery of two (2) ultra high-rate gas wells (+200 MMscf/D) completed in a depleted gas reservoir with 9⅝ in. production tubing and an Open-Hole Gravel Pack (OHGP). Maximizing gas off-take rates from a volumetric drive gas reservoir that possess high flow capacity (kh) require large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of wells completed with 9⅝ in. production tubing ("big bore") determined that this design concept was feasible and deliverable in a short time frame while still maintaining engineering rigor. The paper will highlight key accomplishments within various phases of a completion delivery process for critical wells. The completions were installed with minimal issues (NPT≈ 9%) and have produced without incident. The wells are capable of +250 MMscf/D and are currently producing at +220 MMscf/D.
On the Hydraulics of Inverted Flow Path Gravel Pack Operations
Authors: Rao B. N. , Amin A. M. , Van Petegeg R. , Broussard J. 
Published: June 2014

Abstract
The hydraulics of inverted flow path gravel pack operations is studied utilizing a transient flow simulator. Inverted flow path or more simply, inverted gravel packs can be employed in horizontal or fishhook wells wherein the well/screen annulus is partially packed first in the toe-to-heel direction (alpha wave) followed by packing in the heel-to-toe direction (beta wave) to complete the pack.
Until the present time, conventional gravel packs in which the well/screen annulus is partially packed in the heel-to-toe direction (alpha wave) prior to completing the pack in the toe-to-heel direction (beta wave) have primarily been utilized for sand control in horizontal or deviated wells. In addition, alternate flow path technology (e.g. shunt tubes) has also been utilized along with conventional gravel packs. However, in the case of fishhook wells, conventional gravel packs may need to surmount an uphill slope during the alpha wave and can cause operational difficulties such as premature bridging and fracturing the formation at the heel during the beta wave. These operational difficulties may be overcome by employing inverted gravel packs wherein slurry is delivered into the well/screen annulus at the toe and the alpha wave is performed along the downhill slope thereby reducing the risk of formation fracturing at the heel and premature bridging in the annulus.
In this paper, hydraulics of inverted flow path gravel packs is investigated utilizing a transient flow simulator. A field example is considered and a comparative study is performed on the hydraulics of inverted and conventional gravel pack operations. Results from the field example simulations are discussed from both steady-state and transient view points. Steady-state results include pressure profiles with measured depth for select slurry front locations in the well/screen annulus. Transient results are presented as variations of pump, gravel pack packer (heel), bottomhole (toe), and maximum well/screen annulus pressure with elapsed time. These simulations in conjunction with a mathematical analysis provide some insight into the inverted gravel pack hydraulics and associated pressures in comparison with conventional gravel packs. Results show that inverted gravel packs significantly reduce the maximum pressures experienced in the well/screen annulus compared to conventional gravel packing.
The Extinction of Skin
Authors: Byrne M. T. , McPhee C. A. 
Published: June 2014

Abstract
The concept of "skin" has been with us for a long time. Numerous different definitions exist but normally a skin is considered a dimensionless factor calculated to determine or explain deviation from a well’s ideal (or theoretical) behaviour. Skin is often considered to include the impact of formation damage or "reduced near wellbore permeability" and provides a convenient catch-all for any number of different phenomena that affect well performance. This concept, which avoids attempting to fully capture and understand system performance, would not be tolerated in other engineering industries. It is time to reconsider our use and abuse of skin and move to a more systematic and physically rigourous description of well performance and formation damage.
When a well is drilled there are multiple factors that influence the well performance or the ability of fluid to flow in to or out of the well. The key factors are the reservoir properties and the geometry of the wellbore and how this geometry interacts with the reservoir. Rather than relating varied and diverse well geometries such as perforations, hydraulic fractures, chemically-induced fractures or channels, to a simple cylindrical base case well and calling the "difference" in well performance "skin" we can, and should, detail the well geometry. Too often the good or excellent well performance from stimulated wells is mis-attributed to a negative skin and no formation damage when the principal "stimulation" has been a significant change in the wellbore geometry. If the well geometry can be defined then we can evaluate how the well performance compares with expectation for that geometry without invoking skin.
Using examples of real well performance and formation damage, a procedure is presented which demonstrates the advantages gained from understanding real wellbore geometry and the advances that extinction of skin factors brings to well planning and performance.
Skin is an outdated and misleading concept and an expedient tool for justifying drilling and completion design and well performance. The challenges in modeling such a complex system should never be underestimated but it is clear that better well planning and better understanding of well productivity and formation damage will be possible if we include the well geometry in our assessment and eliminate "skin".
Reaction of Emulsified Acids With Dolomite
Authors: Sayed Mohammed , Nasr-El-Din Hisham A. , Nasrabadi Hadi 
Published: June 2014

Summary
Emulsified acids have been used in the oil field for many years. They are retarded systems that can be used effectively in stimulation of carbonate reservoirs. Emulsified acids have been used primarily in acid fracturing and matrix acidizing. The delayed nature of emulsified acids is useful in generating longer etched fractures or deeper wormholes. To predict the penetration depth of the wormholes or the length obtained from an acid-fracturing treatment, diffusion-coefficient values need to be estimated. This paper discusses the reaction kinetics of dolomite disks with emulsified acids formulated using a cationic emulsifier. The emulsified acid systems were prepared using 15 wt% HCl and 0.7 acid volume fraction. The emulsifier concentration was varied from 0.5 to 2.0 vol%. Emulsified-acid reaction rates and, hence, acid diffusivity were measured using a rotating disk apparatus at 230°F. Disk-rotational speed was varied from 100 to 1,500 rev/min. Samples of the reacted acid were collected and analyzed using the inductively coupled plasma (ICP) mass spectrometry to measure calcium and magnesium concentrations. The dolomite core samples reacted slowly with emulsified acid. Emulsions with low emulsifier concentrations (0.5 vol%) had average droplet sizes of 8.118 lm and achieved a diffusion coefficient of 1.413x10-8 m2/s. While emulsions prepared with higher emulsifier concentration (2.0 vol%) had a smaller droplet size (2.82 lm), they achieved a diffusion coefficient of 8.367x10-10 cm2/s. Reaction of dolomite with emulsified acid at 230°F was found to be mass-transfer limited. Compared with calcite, the dissolution rate of dolomite in emulsified acids was lower by one order of magnitude, and the diffusion coefficient of acid was lower by two orders of magnitude.
Moving Beyond the Capillary Suction Time Test
Authors: Pagels Markus , Hinkel Jerald J. , Willberg Dean 
Published: June 2014

Abstract
The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material, and the capillary suction time (CST) test has become a standard test method. However, the CST test is designed to measure particle flocculation and specific filtration, and as such is not constructed to differentiate the relative impact of either clay swelling or wetting alteration effects. The CST test produces an amalgamated result of several processes and cannot be scaled back to one particular process.
While the CST test has been used to gain an overview of fluid issues, it also introduces a medium (paper) that is far different from anything found in a reservoir. The rate of imbibition into the paper will be affected by fluid/paper interactions. Efforts to model results from CST tests have not been successful; its results cannot be plugged into a model. The millions of CST tests performed have not enhanced the industry’s insight into rock/fluid interactions. Given that the CST test has no theoretical basis and given the lack of standardization with respect to both testing methodology and the interpretation of results, there is a great need for an improved test method.
In order to evaluate the impact a treatment fluid has on the reservoir rock, the actual wetting conditions need to be determined. Treatment fluids and additives, e.g. clay stabilizers and surfactants, can alter the wetting characteristics of the rock surface. A direct measure of wettability is the contact angle.
We have identified a new method to determine the dynamic advancing contact angle on a small amount of sample that allows us to quickly and quantitatively explore the alteration of the rock wettability by the fluid and additives. Results from the new test method are quantitative and can be plugged into a model. We applied this simple and theoretically sound test method to material from different formations, using a multitude of different fluids and evaluated how the treating fluid interacts with the formation material. We show how the new method can determine the tendency of the rock to imbibe fluid.
A Solids-Free Permeability Modifier for Application in Producing and Injection Wells
Authors: Lastre M. , Milne A. 
Published: June 2014

Abstract
Most currently available relative permeability modifiers (RPM) are polymers that, due to electrostatic charges, adhere to the surface of the pore spaces in a porous medium and result in a disproportionate permeability reduction (DPR) to water. However, there are a number of known limitations associated with the use of a polymer in low-permeability formations (&lt;50 mD). The polymer may physically block the pore throats. The higher viscosity (with respect to formation water and in some cases crude) of the polymer solution will self-divert the treatment into the intervals with the highest permeability, regardless of the oil/water saturation.
One solution for low permeability reservoirs is the use of solids free viscoelastic surfactant based fluid.
However, core flow testing showed that the disproportionate permeability reduction to water using cationic, anionic and zwitterionic viscoelastic surfactants is markedly different. The performance of cationic and anionic surfactants varies greatly depending on mineralogy and crude oil composition, in some cases increasing the effective permeability to water. While, a zwitterionic surfactant at concentrations below the critical micelle concentration consistently results in a disproportionate permeability reduction to water, irrespective of the mineralogy or composition of the crude oil. In certain cases, the permeability to oil increases and residual oil saturation decreases significantly.
An extensive study was carried out to evaluate the performance of a viscoelastic RPM. The properties of a viscoelastic RPM makes it a very versatile fluid system. In high water-cut wells, treatments have reduced the water-oil ratio, by up to 18%. While in oil-wet reservoirs, treatments have effectively stimulated oil production, by more than 10%. Another interesting application has been to treat water injection wells to reduce the residual oil saturation, improving both injection rates and sweep efficiency. These properties make the technology particularly suitable for use in increasing reserves recovery in old/mature fields.