bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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 (<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.
A Specially Designed Organophilic Chloride-Free Reservoir Drill-In Fluid Meets the Challenges of the First Horizontal Well in Mozambique
Authors: Ezeigbo E. , Luyster M. , Ravitz R. , Pereira A. , Nguyen C.
Published: June 2014

An operator was planning to drill the first horizontal well in the Inhassoro field in Mozambique. The type of completion would be an open hole utilizing expandable screen technology. The formation had highly reactive shale stringers necessitating the use of an inhibitive fluid, but due to the environmental restrictions, the use of non-aqueous fluid systems could not be used to drill or complete the horizontal section. The issue of cleaning up the filter cake was examined as it would be confined with the use of the expandable screen. Normally a breaker system would be required to cleanup or disperse the filter cake with this type of completion; but due to the water sensitivity of the reservoir, any aqueous filtercake breaker would have to be left out of the completion process.

The reservoir drill-in system used to drill horizontal section would require an inhibitive water-based fluid that was also chloride free due to possible contact with the ground water. The system would also require a filter cake that could be cleaned up with the producing hydrocarbons due to the absence of any filtercake breaker system. The filter cake must also demonstrate a low permeability in order to limit the invasion of fluid into the sensitive formation. A low coefficient of friction would also be another requirement for the reservoir drill-in system.

This paper will highlight the design optimization, the unique characteristic, the testing and the successful implementation of this special reservoir drill-in system.
Vitality of Formation Damage Causing Microorganisms in Brines
Authors: De Benedictis F. , Schultz K. , Armstrong C. D. , Javora P. , Qu Q.
Published: June 2014

Water for field operations, usually obtained from available sources close to location, often contains high concentrations of bacteria. In order to ensure that bacteria that might cause formation damage, corrosion, pore plugging, or souring is not introduced into the wellbore, bactericide is often added to source waters. However, when used to dilute brines to lower salt concentrations, the addition of bactericide is based on the resulting salinity of the brine.

Laboratory studies were conducted with various brines and densities to determine when the use of a bactericide is necessary to ensure that bacteria-free brine is introduced into the wellbore. Various brine samples were contaminated with field water containing bacteria and the viability of the bacteria was observed periodically for 48 hours. Results indicated that the viability of bacteria was dependent on the nature and type of brine (NaCl, CaCl2, NaBr, CaBr2, KCl, and ZnBr2), the concentration of salt in the test brine, and exposure time of the microorganism to the brine. A minimum exposure time was required to effectively kill bacteria, and this requirement will be discussed in relation to operational parameters and fluid inhibition issues. The mechanism of microbiological vitality of high osmotic conditions will also be discussed.
Effective Kaolinite Damage Control under Unfavorable Chemical Environment: Field Case
Authors: Restrepo A. , Lastre M. , Milne A. , Peñaloza S. J , Castro E.
Published: June 2014

Kaolinite migration is a common but often well treated formation damage mechanism. Undesired secondary reactions leading to precipitates and/or limited treatment coverage related to the presence of additional damage mechanisms are common issues. The present work documents a field case study of kaolinite damage control that included dissolution and stabilization under a very unfavorable environment in which CaCO3 scales and asphaltenes also co-existed. The case herein described is the last development stage after several unsuccessful trials in the same area which included the injection of conventional mud acid and retarded HF sandstone type systems. A new chemistry approach incorporating retarded flouboric acid generation and high performance chelants for metallic ions control was developed. Also key, was realizing fines wettability to oil (through critical rate tests to both water and oil) which allowed including proper pre-flushes on final treatment deployment.

Along with a summary of the fines problem description in the area of interest, laboratory protocols, stimulation design approach and field trial results are presented. According to treated well results, up to 50% PI improvement could be now attained in ~60% of total well count where same damage configuration is expected to be present.
Development of More Environmentally Friendly Demulsifiers
Authors: Zhou Hui , Dismuke Keith I. , Lett Nathan L. , Penny Glenn S.
Published: June 2014

Formation damage caused by water-in-crude oil emulsions can have a big impact on oil production. Chemical treatment is often applied by injecting surfactants known as demulsifiers to break the water-in-crude oil emulsions. Common demulsifiers used in the oilfield industry often contain chemicals that are deemed environmentally unacceptable. With the increasingly stringent environmental and safety measures for oilfield chemicals, there is a significant drive to develop more environmentally friendly formulations for oilfield applications that are as efficient as existing chemicals. In this work, more environmentally friendly demulsifiers have been developed by systematically upgrading existing components in a conventional demulsifier with more environmentally acceptable components. The environmental impact of existing and upgraded formulations was evaluated using industry developed product rating systems. Demulsification tests were then carried out to assess the performance of the newly developed formulations on several problematic oils.
Novel Interconnected Bonded Structure Enhances Proppant Flowback Control
Authors: Burukhin A. , Kalinin S. , Abbott J. , Bulova M. , Wu Y. , Crandall M. , Kadoma I. , Begich M. , Papp S.
Published: June 2014

Loss of proppant from the near wellbore region of a fracture results in fracture pinch out and a noticeable decrease in well productivity. Downhole and surface equipment can be damaged when proppant flowback occurs as well. Resin coated proppant (RCP), fibers, deformable particles, resin on the fly, etc have been used to improve proppant pack stability. Selection of the appropriate proppant flowback control technology is made with consideration of engineering factors such as fluid compatibility issues, setting time, resistance to cycling stress-loading issues, and conductivity damage.

The goal of the current work was to combine the beneficial features of mechanical proppant flowback control with chemical adhesive flowback control products. With mechanical features, the proppant pack stability is enhanced by blending fibers with proppant, thus increasing particle-particle interaction, and increasing the stability of proppant arches. This mechanism can enable aggressive flowback while providing an instantaneous, albeit a modest level of proppant flowback control. With the addition of an adhesive bonding mechanism to a mechanical flowback control material, the bicomponent material substantially increases proppant pack stabilization. Using a high temperature, high pressure proppant flowback control apparatus, we show the impact of particle bonding on the dosing required to achieve a specific level of proppant pack stability. We also show the impact of the flexible nature of bonded matrix on the proppant pack stability and tolerance to cyclic loading.

A mechanistic proppant pack stability model was developed based on our experimental study. We discuss this model and its application towards the selection of the appropriate proppant flowback control technology for specific well conditions. We conclude the paper by discussing field cases of effective proppant flowback prevention techniques deployed as a result of model recommendation.
Extending Reamer Life and Improving Drilling Performance by Optimizing Neutral Points in Bottomhole Assemblies
Authors: Krishingee Roxann J , Ulmer Karl , Posey Byron
Published: June 2014

With the development in drilling technology, operators are now drilling further into unknown temperature and pressure regimes, extending the typical well depth to limits never seen before. To deal with these unseen depths, wellbores are being re-designed with more casing strings. Consequently, under-reamers are being used much more frequently to help achieve the optimum hole size for casing.

In bottomhole assemblies (BHAs) with under-reamers it is not unusual to have two neutral points in the assembly, creating a transition zone between both neutral points. To comprehend the effects of placing a reamer in this transition zone, some field cases with reamers placed in this zone were studied. Based on the findings, the reaming bottomhole assembly was optimized to eliminate dual neutral points, which resulted in extended under-reamer life.

This paper discusses the benefits of optimizing hole-opener placement in regards to neutral points and the transition zone. Some precautionary procedures are mentioned that can be implemented to optimize bottomhole assemblies that include reamers, reduce BHA failures and improve drilling efficiency.
Optimizing Borehole Imaging for Tight Gas Exploration: Evolving a Go-No-Go Decision Tree in Tight Gas Reservoirs of the Sultanate of Oman
Authors: Shrivastva Chandramani , Al-Mahrooqi Sultan , Mjeni Rifaat , Kindy Suleiman , Hosein Feraz , Al-Busaidi Hafidh , Al-Busaidi Jokha , Laronga Robert
Published: June 2014

Borehole images play a crucial role in tight gas exploration. Recognition of sedimentary features helps in understanding the depositional architecture and allows refinement of the facies model for flow unit identification and stimulation treatment. The structural analysis of faults and fractures provides clues not only about the tectonic history, but also about the possible conduits for fluid migration that lead to diagenesis. The diagenetic imprints and their impact in a sequence stratigraphic framework can be understood through textural analysis performed on the borehole images across the field. And, hydro- fracturing of tight gas reservoirs require important input from the borehole images in understanding the variability of stress regimes.

Established micro-resistivity imagers for the water-base mud (WBM) environment provide robust results, except when there is a large contrast between the formation resistivity (Rt) and the mud resistivity (Rm). With more frequent use of hyper-saline mud, a new and improved definition imager is deployed to obtain high quality images. Novel hardware and improved signal processing algorithms are employed to acquire the images despite the hostile conditions provided by the combination of low- resistivity salt-saturated (WBM) and high formation resistivity that would otherwise impede the data quality. Early field testing of this enhanced capability took place in the Sultanate of Oman and the examples of its improved performance are presented.

Getting the most detailed image data in oil-base mud (OBM) is challenging compared to the WBM systems. As an alternative to the options commercially available in the industry today, the new high-definition imager developed for the WBM system can also be used under favorable conditions to acquire valid images in the OBM. The high-definition imager works best in OBM when both formation resistivity and mud permittivity are high.

A workflow is developed for the Go – No Go decisions for borehole imaging tools in different mud systems for tight gas reservoirs. It is important at the planning phase of the logging programs to anticipate the imaging tool behavior in the proposed mud system and conditions. The results from trials made in the tight gas reservoirs of North Oman provided the basis for a decision tree for imaging, since the logging environment exerts a strong control on data quality. The decision-tree presented here aims to ensure that images acquired are the most suitable for detailed geologic interpretation and subsequent integration in development plans for optimal exploitation of tight gas sands in Oman.
The Linear Displacement of Oil from Porous Media by Enriched Gas
Authors: Welge H.J. , Johnson E.F. , Ewing S.P. , Brinkman F.H.
Published: June 2014

This paper presents a method for predicting the manner in which oil will be displaced from a porous body by enriched gas. The calculations apply to a gas rich enough to give a partially, but not a completely, miscible displacement. The method - a three-component, two-phase analysis - takes into account condensation of some of the intermediate hydrocarbons from the injected gas into the oil, as well as enhanced volatility of heavier hydrocarbons at elevated pressures and temperatures. The condensation swells the oil and decreases its viscosity, thus aiding in its recovery.

The calculations have been extended to apply to actual crude oil-natural gas systems by arranging the components into three groups according to their volatility. As an approximation, each group is then treated as a single component in the analysis. The influence of an angle of dip for an inclined displacement is also taken into account.

The recovery predictions are corroborated by experiments which used both consolidated sand cores and unconsolidated glass beads. In some of these tests, actual live crude oil was displaced by amulticomponent gas typical of enriched gases used in oil fields.

Introduction

This paper presents a method for predicting the amount of oil that can be displaced from a homogeneous, linear, porous body at various stages during the injection of enriched, or "wet", gas. The porous body can be in either a horizontal or an inclined position. This type of displacement is sometimes known as "condensing gas drive". The method is developed especially for the case in which the injected gas is enriched enough to be partially, but not completely, miscible with the reservoir oil. The need for a calculative procedure for this type of operation is emphasized by the number of field projects where completely miscible drives are not practical, but where near-miscible conditions are feasible.
Laboratory Studies of Oil Recovery by Steam Injection
Authors: Willman B.T. , Valleroy V.V. , Runberg G.W. , Cornelius A.J. , Powers L.W.
Published: June 2014

This paper reports the results of an investigation into the use of steam as a recovery agent. High oil recoveries by steam, as much as 100 per cent greater than by water flood, were demonstrated in laboratory linear cores. The principal mechanisms responsible for the additional oil have been identified asthermal expansion of the oil,viscosity reduction andsteam distillation.

Although the first two also enhance recovery by hot water flood, they are effective with steam injection at lower volumes of produced fluids. Steam-zone residual oil saturation is independent of initial saturation. Recovery by steam is greater for lighter oils because they contain a greater fraction of steam-distillable components. Equations for the steam-zone advance in a radial homogeneous system are presented; these show the effect of reservoir parameters. The displacement in the hot liquid region moving ahead of the steam front can be estimated by a calculative procedure which is suggested. The method which takes account of the temperature gradient is applicable also to a regular hot water flood.

Introduction

Considerable industry interest in the application of heat to petroleum reservoirs as a means of increasing oil recovery has been evident in the past few years. Three thermal methods which have attracted interest arethe injection of saturated steam,the injection of hot water andthe injection of air into a formation to support combustion within the reservoir.

Much has been published in recent years on underground burning, and there have been several papers on hot water injection. Although there are several early reports on steam injection, no recent experimental studies have been published on this recovery method. In our early thermal methods research, a marked improvement was found in oil recovery by steam injection compared with recovery by water injection in the same system. An investigation subsequently was undertaken to obtain quantitative information from which to evaluate steam injection as an oil recovery method. In addition, it was desired to investigate the recovery mechanism of hot water as compared with that of "cold" water and steam injection. An understanding of the mechanisms by which these processes operate would generally define favorable field conditions for their successful application. This paper reports the results of the laboratory study and suggests calculative approaches to estimate the field behavior of the steam-injection process.
Wellbore Solids Removal Coiled Tubing and Vacuum Technology in Heavy Oil Horizontal Wells in North Central Alberta
Authors: Parra A. A. , Bosilca D.
Published: June 2014

Recently a new coiled tubing technology has been used to clean out horizontal wellbores with a low downhole pressure. This technique uses a dual coiled tubing string and a special vacuum tool designed to create a pressure drop across the formation sand face in order to clean out formation fines, unwanted fluids and solids. The work string, used for this application, has a rectangular matrix design; the two 1-1/2"coiled tubing strings are encapsulated into one uniform body using a high strength thermoplastic jacket. The power fluid is circulated down through one of the strings and the returns, including fines and solids, are transported to surface, up the second string. To operate the system, a custom coiled tubing reel, with two rotating joints was designed. The fluid goes through a jet pump (BHA), where it passes through a nozzle creating a "Venturi effect". New software has been developed to simulate the torque and drag, given that the cross section area is similar to a rectangle and it has two contact points, instead of one. A hydraulic simulation has been performed to determine the jet pump performance, circulation rates and pressures. Real time data was used to calibrate the models.

The technology has been used for liner clean outs, in horizontal heavy oil (8 API) wells, with low pressure averaging 362 psi at 2625 ft (2.5 MPa; 800 m TVD; ) reservoirs.

In the first well, 656 feet (200 meters) of 5-1/2" horizontal slotted liner was cleaned out down to 3008 feet (916 meters) and 4.7 barrels (745 liters) of sand were circulated out to surface (30% of the total internal volume). In the first well the production was recovered from an initial rate 6 bbls/day to 31 bbls/day (1 m3/day to 5 m3/day). In the second well, with 5% H2S, the dual coiled tubing was run in the 4- 1/2" production tubing and the 4-1/2" horizontal slotted liner was cleaned out down to 3550 feet (1082 meters).

Based on the results, this technology is proven to be a viable solution for cleaning long horizontal wells with low bottom hole pressures.
Data Blocking or Zoning: Well-Log-Data Application
Authors: Al-Adani Nabil
Published: June 2014

Several statistical techniques have been introduced in zoning sequential data such as well-log data or blocking experimental data. In general, these techniques lack the ability to optimize the predicted zones as per the desired number of blocks or zones. In addition, all these techniques' results depend on the amount of data inclusion in the blocking or zonation process. In this paper, a new method has been introduced to address the blocks or zones optimization and data-amount dependency. The new method also helps in establishing a new approach in estimating the data random error, if not known. This paper does not compare all techniques with the proposed approach. One technique has been selected to highlight the advantages of the proposed method.

An example of a Canadian oil-sand well has been used to demonstrate some applications of the new blocking or zoning method.
Oil Field Chemicals Synergy Upstream Arab Heavy Crude Handling Facilities
Authors: Achuo Kima Enow
Published: June 2014

The presentation key objective is to show how synergizing the use of corrosion inhibitor and demulsifiers has enhanced the performance and optimized the cost of Oil Field Chemical (OFC) treatment at Safaniya Onshore Arab Heavy wet crude handling facilities. The various steps involved in synergizing the use of oil field chemicals at Safaniya Onshore Arab Heavy wet crude handling facilities have also been discussed.

The key performance factors used to assess the overall impact of the process including the total cost of chemical treatment, the effective mitigation of corrosion in the system, the oil in water content in the produced water system, other process parameters like emulsion and foaming tendency were addressed.

Synergizing the use of OFC at Safaniya Onshore Arab Heavy wet crude handling facilities has resulted in chemical treatment cost savings of approximately $2.0 MM per year, better treatment of produced water system and improved corrosion mitigation efficiency of 99.6%.
Maximum Permissible Dog-Legs in Rotary Boreholes
Authors: Lubinski Arthur
Published: June 2014

In drilling operations, attention generally is given to hole angles rather than to changes of angle, in spite of the fact that the latter are responsible for drilling and production troubles. The paper presents means for specifying maximum permissible changes of hole angle to insure a trouble-free hole, using a minimum amount of surveys. It is expected that the paper will result in a decrease of drilling costs, not only by avoiding troubles, but also by removing the fear of such troubles.

Summary, Conclusions, and Recommendations

Excessive dog-legs result in such troubles as fatigue failures of drill pipe, fatigue failures of drill-collar connections, worn tool joints and drill pipe, key seats, grooved casing, etc. Most of these detrimental effects greatly increase with the amount of tension to which drill pipe is subjected in the dog-leg. Therefore, the closer a dog-leg is to the total anticipated depth, the greater becomes its acceptable severity.

Very large collar-to-hole clearances will cause fatigue of drill-collar connections and shorten their life, even in very mild dog-legs. Another finding regarding fatiguing of collar connections in dog-legs is that rotating with the bit off bottom sometimes may be worse than drilling with the full weight of drill collars on the bit, mainly in highly inclined holes when the inclination decreases with depth in the dog-leg.

Means are given for specifying maximum dog-legs compatible with trouble-free holes. An inexpensive technique proposed is to take inclinometer or directional surveys far apart; then, if an excessive dog-leg is detected in some interval, intermediate close-spaced surveys are run in this interval.

The application of the findings should result in a decrease of drilling costs, not only by avoiding troubles, but mainly by removing the fear of such troubles. The result would be much more frequent drilling with heavy weights on bit, regardless of hole deviation.
Laboratory Drilling Performance of the Full-Scale Rock Bit
Authors: Rowley D.S. , Howe R.J. , Deily F.H.
Published: June 2014

Laboratory drilling tests with 4 3/4-in. hard-formation rock bits were made under rock pressure and borehole fluid pressures simulating a 3,000-ft borehole. The effects of bit weight and rotary speed on drilling rate and bit rotary power were determined in a hard, impermeable dolomite. With added bit weight, the drilling rate and rotary power both increased at an increasing rate; but, with added rotary speed, the rate and power both increased at a decreasing rate. The rock volume removed per unit of energy increased as weight was raised or as rotary speed was reduced. Empiric quadratic equations for drilling rate and rotary power were obtained and bit mechanical efficiency was calculated.

Introduction

During the past three years, Jersey Production Research Co. has performed an extensive series of tests using roller cone, drag and diamond bits varying in size from 3 3/4 to 9 7/8 in. These tests have been made under a wide range of drilling conditions in several types of rocks at both atmospheric pressure and elevated pressures simulating depths to 3,000 ft. This paper reports the effects of bit weight and rotary speed on the penetration rate of and power consumed by a 4 3/4-in. hard-formation rock bit drilling in impermeable dolomite.

The laboratory work reported here supplements and extends previously published data describing the effects of bit weight and rotary speed on drilling rate from tests made at atmospheric pressure. Similarly, the effects of pressure have been previously investigated, using 114-in. "microbits", and the effects on drilling rate of pressure and fluid environments have been reported. Several investigators have also studied certain theoretical aspects of the roller-cone rock bit performance problem. Despite this work, however, there are no published data available on the performance of field sized bits under controlled laboratory conditions which simulate the down-hole pressure environment. There also is very little information in the referenced papers on the amount of power consumed by the bit. Therefore, the purposes of this paper areto present laboratory performance data on a field-sized bit to aid in the interpretation of field test results, andto make data available on the rotary power at the bit.

It is hoped that this information will stimulate industry studies of energy consumption in rotary drilling and lead to the improvement of drill-bit efficiency.
New Correlations for Dew-Point Pressure for Gas Condensate
Authors: Al-Dhamen Mohammad , Al-Marhoun Muhammad
Published: June 2014

New Models with three different techniques have been developed to predict the dew-point pressure for gas condensate reservoirs. Traditional correlations, non-parametric approaches and artificial neural networks have been utilized in this study. The new models are function of easily obtained parameters (reservoir temperature, gas specific gravity, condensate specific gravity and gas-oil ratio). A total number of 113 data sets obtained from Constant Mass Expansion experiment (CME) were collected from Middle East fields; has been used in developing the models. The data used for developing the models covers a reservoir temperature from 100 to 309 oF, gas oil ratios from 3,321 to 103,536 SCF/STB, gas specific gravity from 0.64 to 0.82 and condensate specific gravity from 0.73 to 0.81. The artificial neural network developed in this study has the best results among all other models with an average absolute error of 6.5%. Graphical and statistical tools have been utilized for the sake of comparing the performance of the new models and empirical models available in literature.
The Evaluation of Vertical-Lift Performance in Producing Wells
Authors: McAfee R.V.
Published: June 2014

The fundamentals of vertical-lift performance are examined with the aid of computer-calculated flowing gradient charts. Flowing and gas-lift well performance characteristics are determined from available well test data. The effect of tubing size, gas-liquid ratio and wellhead pressure is discussed for both flowing and gas-lift wells. The effect of gas-injection pressure, formation gas, bottom-hole pressure and valve spacing is also discussed for gas lift wells. From these studies conclusions may be reached for improving or prolonging natural flow, obtaining optimum lift efficiency when natural flow ceases and improving existing gas-lift systems. The techniques perfected satisfy the requirement that the time involved to conduct an evaluation be practical for operating personnel.

Introduction

Flowing pressure gradients furnish the key to successful evaluation of vertical-lift performance in producing wells. Command of multiphase flow gradients in some readily usable form is a necessity before operating personnel can competently include vertical-lift performance evaluation of both flowing and artificial-lift wells in their over-all consideration of production efficiency. A readily usable form cannot be overemphasized since most of the decisions which confront the production engineer with a problem well must be made quickly. In moving a barrel of oil from the reservoir to the stock tank, the major portion of energy generally is expended in the vertical-lift phase. This may or may not be of concern during the flowing life of a well, depending upon the production requirements. It becomes of some concern when the flow performance of the well becomes erratic, and a conscious effort must be made to maintain natural flow. It is at this time that the first steps may be taken to modify existing conditions to relieve unnecessary limitations to proper flow.

When natural flow ceases and some form of artificial lift must be installed, the amount of energy expended in lifting liquids becomes quite obvious. It is at this time, if no other, that lifting efficiency becomes important because that part which must be supplied from an outside source is now related directly as a cost per barrel of oil produced.
Influence of Property Modeling Practices on Estimated Hydrocarbon Pore Volume
Authors: Bust Vivian K. , Worthington Paul F.
Published: June 2014

The emergence in geoscience of 3D geocellular modeling has raised questions about the correspondence of hydrocarbon volumetric deliverables with those derived from 2D zonal modeling. These differences of approach are compounded because the contemporary 3D methods use net-reservoir volumetric algorithms whereas the more established 2D methods have traditionally used net-pay volumetric algorithms. Both methods are initialized using 1D “along-wellbore” datasets. Key parameters for comparison are initial hydrocarbon pore volume (IHPV) for 2D and 3D modeling and equivalent hydrocarbon column (EHC) for 1D along-wellbore modeling.

The focus is twofold. The first objective has been to generate a functional petrophysical model as a basis for volumetric comparisons. The reservoir notionally comprises an oil accumulation within a water-wet, lithologically-clean sandstone that is partially saturated with high-salinity brine. The sandstone comprises five rock types (RTs), each of which has a defined set of interpretive algorithms. The second objective has been to compare static volumetric estimates of EHC and/or IHPV for a range of case models. This objective was approached using three workflows. Initially, 1D along-wellbore screening studies used different case models representing various stratigraphic sequences. These allowed a preliminary assessment of results arising from the use of net-reservoir and net-pay volumetric algorithms without the influence of mapping practices. The findings were corroborated by field studies. Second, 2D zonal modeling led to values of IHPV based on both net-reservoir and net-pay algorithmic protocols. Third, 3D geocellular modeling also led to values of IHPV based on both protocols. These data allowed equitable comparisons of 2D zonal deliverables with those from 3D geocellular models because a consistent inter-well interpolation methodology was used for all 2D and 3D cases.

The analysis incorporated the influence of stratigraphic sequences of the five RTs with their different petrophysical characteristics. Comparisons of 2D and 3D models showed that IHPV values delivered by established 2D zonal models with net-pay algorithmic protocols are mostly lower than those values delivered by contemporary 3D geocellular models with net-reservoir protocols by approximately 4% on average, but the differences are highly variable. These outcomes, which have implications for reserves estimation, are strongly governed by the stratigraphic distribution of the RTs. They re-emphasize that each case must be investigated separately and thoroughly.