bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Drilling Strategies in a Tectonic Belt, Pagerungan Field, North of Bali
Authors: Mouton D.E. , Wilton B.S. , Ramos G.G. 
Published: December 2007

Abstract
Initial development drilling programs in the Pagerungan Gas Field were plagued by severe hole problems caused by tectonic stresses and dispersive formations, shallow gas events and logging problems. An optimization study was conducted using a database generated from 14 wells drilled over the past ten years. The results of this study showed that significant improvements in drilling performance could be achieved.
A technique using wellbore stability days as an index was used to account for time-dependent effects of water-base mud systems on dispersive formations. This technique enabled an empirical refinement of a static-elastic wellbore stress model. Additionally, the use of a synthetic-base mud system eliminated the time-dependent effects allowing lower mud densities, casing string reductions, and dramatic increases in rates of penetration. A "batch" drilling/completion schedule accelerated the learning curve effect and optimized the program's logistical efficiency.
By implementing the recommendations of the optimization study, improvements as high as 30% in drilling performance were achieved without compromising safety. As a result, significant financial savings were realized for the program.
P. 559
Turnkey Drilling: Bringing Cost Predictability to a Risky Business
Authors: Baum K.E. , Munson J.R. , Marshall J.A. , Vrooman D.K. 
Published: December 2007

Abstract
Drilling has been and always will be a risky business. Every well is unique and capable of encountering problems far beyond anyone's original expectations. Whether drilling a rank wildcat or the twentieth development well in a field, the risks of our business do not go away. In fact, the risks seem to multiply over time, as wells become more complex due to advances in technology. With this increased operational risk comes additional financial exposure as the cost of all operations has continued to escalate over the recent past.
Performance against predetermined financial goals of an operation is the most universally accepted way to evaluate the success or failure of a project. Turnkey is the only drilling alternative which can cap financial exposure and in the process offer operators the requisite flexibility to conduct their business and manage their resources in a more efficient manner. It is this capability to fix costs, and shift drilling risk that is inking turnkey an increasingly more attractive alternative to operating companies of every size. Turnkey is no longer just a drilling decision; but has become, more importantly, a business decision.
P. 593
Rejuvenating Engineering Students Interest in the Oil Business
Authors: Smith Jack , Warren Diane 
Published: December 2007

Abstract
The downturn of the oil business in the mid 80's and the often heard negative news relating to environmental issues has resulted in a reluctance of present day engineering students to enter this business. This has a dramatic impact on our industry's ability to design and produce new products and to advance the technologies. This paper discusses a four step approach to add technical people to the work force and encourage engineering students to consider careers in the oil business.
These four steps are: Hiring engineering students to work part time as drafters, lab technicians and engineering clerks.Participating in university engineering Co-op programs.Sponsoring engineering student design projects.Using university faculty members as consultants to help on technical problems.
The positive contributions received from these activities and comments and projections on the long term objectives are discussed.
Well Examination – Self Regulation in a Goal Setting Environment
Authors: King Gregory , Dobson Donald 
Published: December 2007

Abstract
Safety in the offshore oil and gas industry in the UK is now enforced through a system of Goal Setting regulations which require companies to set standards and then demonstrate how these are achieved. Within this system the safety of wells and well work is controlled by a requirement for Operators to develop and apply Well Examination Schemes where work programmes are reviewed by Independent and Competent examiners. The paper describes the previous scheme based upon explicit Government approval; the relevant elements of the Goal Setting environment; and how Well Examination Schemes have been developed, how they operate, and the impact of Well Examination for companies working in the UK.
Minimising Down Hole Mud Losses
Authors: Rojas J.C. , Bern P.A. , Fitzgerald B.L. , Modi S. , Bezant P.N. 
Published: December 2007

Abstract
The application of particle sealing technology, field monitoring techniques and improved operational practices has been used to minimise downhole lost circulation while drilling extended-reach wells. These techniques have been applied at the Wytch Farm Development in Southern England and in the Pompano Development in the Gulf of Mexico. Using particle sealing technology, losses were reduced from an average 5,000 bbls of low toxicity mineral oil to zero while drilling the 8" section in offset Wytch Farm wells M-07, M-09 and down hole synthetic mud looses were significantly reduced on Pompano A-l8. Pressure While Drilling (PWD) data have contributed to the improved understanding of how changes in downhole pressure influence lost circulation.
P. 871
Stimulation of Tight Carbonate Reservoirs Using Acid-in-Diesel Emulsions: Field Application
Authors: Al-Anazi H.A. , Nasr-El-Din H.A. , Mohamed S.K. 
Published: December 2007

Abstract
An oil producing well (Well-A) in a carbonate reservoir was dead due to severe formation damage. The well was acidized by regular 15 wt% HCl, but remained dead. A thorough experimental study was conducted to evaluate using acid-in- diesel emulsions, 70 vol% HCl (15 wt%):30 vol% diesel, to stimulate this well which had several tight zones.
Experimental results indicated that the acid-in-diesel emulsion was a viscous and non-Newtonian fluid. The thermal stability of the acid decreased as temperature was increased. The stability of emulsified acid also decreased in the presence of reservoir rock. The emulsified acid was found to be compatible with native crude oil and acid additives, except mutual solvents and demulsifiers. The reactivity of the emulsified acid with reservoir rock was slower than that of the 15 wt% HCl by a factor of 45 at 24 C. The reaction rate of the emulsified acid increased as temperature was increased.
Coreflood results showed that the emulsified acid formed deep wormholes in tight carbonate cores (&lt; 50 md). At the same acid volume and flow rate, the emulsified acid penetrated deeper into the core compared to the regular acid which caused face dissolution. Permeability ratio (final/initial) of reservoir cores exponentially increased with the acid injection rate. The size and number of the wormholes depended on the acid injection rate.
The acid-in-diesel was successfully applied in Well-A using a coiled tubing unit, whereby the well productivity has been increased by several orders of magnitude. After the treatment, a flowmeter test indicated that the percentage production of tight zones has increased by a factor of 2.
P. 9
A Systematic Study of Iron Control Chemicals Used During Well Stimulation
Authors: Taylor K. C. , Nasr-El-Din H. A. , Al-Alawi M. J. 
Published: December 2007

Abstract
A new type of experimental procedure was used to study iron control chemicals (citric acid, nitrilotriacetic acid and acetic acid) in acidizing treatments at temperatures from 25 to 95°C. This procedure gives plots of iron in solution versus equilibrium pH, while previous work has generally studied iron concentration in completely spent acid solutions. Hydrochloric acid concentrations of 7.5 to 28 wt%, sodium chloride concentrations of 0 to 5 wt%, and iron (III) concentrations from 1,000 to 10,000 ppm were examined with varying concentrations of commonly used iron control chemicals. A systematic study of this kind has not previously been reported in the literature. The following new results were found: Iron (III) hydroxide precipitated from spent acid at much lower values of pH than is generally believed in the literature. The general belief is that iron (III) hydroxide precipitation begins at a pH of about 2.2 and is complete at a pH of 3.3. From experimental results, precipitation begins at pH values of about 1 and is nearly complete by pH 2 at 25 C.As the temperature was increased, iron (III) became significantly less soluble in the spent acid. This means that iron (III) hydroxide precipitation is potentially more damaging to the formation than generally believed.Time-dependent iron precipitation can occur in the absence of iron control chemicals.Time-dependent precipitation of ferric/calcium complexes with nitrilotriacetic acid (NTA) and citric acid was found. In partially spent acid, precipitation of previously unreported complexes containing iron/calcium/chelating agent in a 1/1/1 mole ratio was observed. This behavior is important because of potential formation damage during the acidizing treatment itself, or during shut-in of the well after stimulation.Synergism with citric acid/acetic acid mixtures was found. These two iron control chemicals were able to prevent iron precipitation better in combination than individually.
On-site Evaluation of Acidizing Treatment of a Gas Reservoir
Authors: Zhu D. , Hill A. D. , da Motta E. P. 
Published: December 2007

Abstract
Real-time monitoring (on-site evaluation) of acid treatments for oil reservoirs has been developed and applied in the field successfully.1,2,3 The technique uses the transient flow equation to estimate the skin factor evolution during the treatment, in order to evaluate and enhance the effectiveness of stimulation and diversion. The equation used in the real- time monitoring model assumes that the reservoir fluid is single-phase and slightly compressible. This approach has worked well in monitoring skin factor change during acidizing of oil wells; however, when acidizing a gas well, injection of liquidphase acid strongly affects the apparent skin factor because the estimated skin factor depends on the viscosity difference between the reservoir fluid and the injected fluid. The skin factor calculated by the single-phase oil model is wrong if the viscosity contrast is significant. This paper presents a new model to estimate the apparent skin factor for gas reservoirs during acidizing treatments. The model introduces a viscous skin factor to handle the effect of the viscosity difference between the injected fluid and the reservoir fluid on the pressure response. By subtracting the viscous skin factor, which can be calculated as a function of injected acid volume, from the total skin factor obtained from the rate and pressure recorded during the treatment, the true damage skin during an acid treatment is obtained.
Field examples from Brazil show that the real-time monitoring model for acidizing treatments for gas reservoirs has been used to predict the evolving damage skin factor successfully. The examples presented in this paper show that without accounting for the viscous skin effect, the apparent skin factor for the wells rose during the treatment, which could lead to an incorrect interpretation that the treatments were ineffective. However, when the viscous skin was subtracted from the total apparent skin factor, it was seen that the damage skin was decreasing throughout the treatments, as desired. The production data for the wells before and after acidizing confirmed the predicted skin factor behavior by the new model.
The Effect of Near-Wellbore Fracture Geometry on Fracture Execution and Post-Treatment Production of Deviated and Horizontal Wells
Authors: Chen Z. , Economides M.J. 
Published: December 2007

Abstract
The near-wellbore fracture geometry is important to hydraulic fracture execution and the subsequent post- treatment well performance. A fracture from an arbitrarily-oriented well "cuts" the wellbore at an angle and this limits the communication between the wellbore and reservoir. The stress concentration around the wellbore further complicates the near-wellbore fracture geometry. The fracture width at the wellbore can be much smaller than the maximum width, or it may even close when the fracturing pressure decreases below some critical value. The limited communication path may cause a "screenout" during fracture execution or large reduction in the subsequent production because of choked fracture effects. This paper first discusses fracturing conditions for an optimal communication path between the wellbore and the reservoir. The near-wellbore fracture geometry is then determined. The effects of this fracture geometry on fracture execution and production are discussed. Critical fracturing pressures are also calculated for different wellbore orientations and in-situ principal stress magnitudes. Guidelines are provided to enhance the success of fracturing treatments.
P. 75
The Effect of Frac-Fluid Density on Hydraulic Fracture Growth Direction and Width
Authors: Deeg Wolfgang F.J. 
Published: December 2007

Abstract
In the absence of significant formation-stress contrasts between adjacentzones, the frac-fluid density will determine the preferred growth direction of a vertical hydraulic fracture. A vertical hydraulic fracture will grow in aradial or penny-shaped manner if the frac-fluid density is approximately equal to the gradient of the least principal formation stress. Upward growth is favored if the formation-stress gradient exceeds the frac-fluid density.
Even in the presence of significant stress barriers, frac-fluid density may influence the fracture-growth direction within the pay zone and after the hydraulic fracture has penetrated into the barrier layers.
This paper presents a closed-form solution to rapidly assess the effect of treatment fluid density and proppant loading on hydraulic fracture growth direction and width under a given formation-stress state. This solution was used to:
Explain the apparent lack of downward growth in specific hydraulic fracture stimulation treatments
Confirm that large treatment intervals can be successfully stimulated with one treatment
Determine where a horizontal well should be located within the pay zone to maximize coverage by subsequent fracture treatments
These solutions have been successfully used to answer questions such as:
P. 91
Enhancing Fracture Conductivity Through Surface Modification of Proppant
Authors: Nguyen Phillip D. , Weaver Jim D. , Dewprashad Brahmadeo T. , Parker Mark A. , Terracina John M. 
Published: December 2007

Society of Petroleum Engineers

Abstract
A new liquid surface-modification system has been developed for coating proppant, dramatically increasing its surface friction and allowing it to interact instantaneously with surrounding particulates. High surface friction between the coated proppant grains allows them to withstand high flow rate, minimizing their flowback potential after fracture-stimulation treatments.
According to field results, when this surface-modification material was used as a flowback-control agent after conventional fracturing treatments, it permitted more aggressive flowback procedures. This treatment did not impair conductivity, and in fact, increased proppant conductivity at closure stresses below 4,000 psi. Better vertical proppant distribution occurred in experiments that demonstrated increased hindered settling of proppant resulting from this surface modification. Fines that already existed within the proppant, fines generated from the formation, or fines derived from crushed proppant upon fracture closure all adhered to the treated proppant, which inhibited them from migrating and blocking the pore throats of the proppant pack. This unique coating technology further enhanced conductivity by improving frac-gel breaker action in certain fluids. This behavior results in faster, more effective well cleanup after stimulation.
P. 101
A New Model of Acid Fracure Conductivity Based on Deformation of Surface Asperities
Authors: Gong M. , Lacote S. , Hill A.D. 
Published: December 2007

A New Model of Acid Fracture Conductivity Based on Deformation of Surface Asperities

Abstract
Acid fracture conductivity is affected by the aperture and contact area of the fracture under closure stress. This, in turn, depends on the surface asperities created by the acidizing process and the mechanical strength of these asperities. Acid contact time, acid leakoff, rock mechanical properties, and formation heterogeneity all affect the creation of hydraulic conductivity of an acid fracture.
We have conducted a systematic experimental study to investigate the mechanisms of the creation of hydraulic conductivity in acid fractures, including characterization of the surface roughness created by acid etching, investigation of the damage to the rock compressive strength by acid, and measurement of hydraulic conductivity under closure stress. Experimental data show that longer acid contact results in rougher fracture surfaces and, in turn, higher hydraulic conductivity. However, acidizing also reduces the rock compressive strength causing the surface asperities to easily deform under stress.
Based on our experimental results, a new fracture deformation model was derived which considers both the surface roughness and the rock mechanical properties. The fracture closure under stress is modeled as plastic deformation of asperities. Finally, a cubic law is used to calculate the fracture conductivity. The prediction of acid fracture conductivity using this model with appropriate parameters shows good agreement with the experimental data.
P. 133
Sand Control Completion Design, Installation and Performance of High Rate Gas Wells in the Jupiter Field
Authors: Burton Robert C. , Boggan Stuart A. 
Published: December 2007

Robert C. Burton and Stuart A. Boggan, Conoco

Abstract
This paper provides a review of sand control completion design, installation and subsequent well performance in the Jupiter Field.
The paper reviews formation failure predictions used to assess the need for sand control and discusses the completion designs selected to prevent sand production in a series of high rate gas wells. Completion installation, consisting of running pre-packed screens into the drilled hole, wellbore clean-up and initial well testing is also discussed.
A review of long term sand control effectiveness and completion pressure loss data for these wells is also presented.
P. 149
Case History in Achieving High Rate Producers in Sub Sea Gravel Packed Completions
Authors: Myers Larry G. , Humphreys Neil , Kaminski Henry P. , Bouwaked Elias , Robertson David 
Published: December 2007

Abstract
The Zafiro Field, offshore Equatorial Guinea, was developed as a fast track project with production coming onstream in August, 1996 to an FPSO, less than two years from the field discovery. Downhole gauges with surface readout on the FPSO gave continual monitoring of well performance during early production from the field. These subsea wells, which required sand control, were targeted to produce at rates of 8000 bopd. Early wells made this target with Productivity Indices (PI's) of 6 to 33 bopd/psi. However the data also showed high post completion skin damage when compared to skins measured immediately after TCP operations. This real time data allowed continual improvements to be made in completion designs. This paper is a case history of these design changes which more than doubled PI's, yielding producers capable of 14,000 bopd. Design changes included a move to openhole completions where possible, new screen configurations, fluid studies for optimizing gelled fluids to transport sand in high angle and horizontal openhole completions, filter cake removal in openhole completions, and acid stimulation.
P. 159
New Chemistry and Improved Placement Practices Enhance Resin Consolidation: Case Histories From the Gulf of Mexico
Authors: Parlar M. , Ali S.A. , Hoss R. , Wagner D.J. , King L. , Zeiler C. , Thomas R. 
Published: December 2007

Abstract
Resin consolidation has been used as a sand control method since the early 1940s, most widely between 1960 and 1970, with varying degrees of success. Although, in recent years, the total number of resin consolidation treatments has been quite low compared to Frac-Pack, High Rate Water Pack, and Conventional Gravel Pack treatments, interest in resin treatments has been steadily increasing because resins offer a screenless alternative for sand control completions, making them especially suitable for thru-tubing recompletions.
The success of resin consolidation treatments depends strongly on chemistry of the fluids used in each stage of the treatment (addressing microscopic level failure modes) as well as physics of fluid placement (placement practices to avoid viscous and gravitational instabilities and placement methods to minimize the effects of permeability variations for uniform treatment, both addressing macroscopic level failure modes).
In this paper, we present the new chemistry and improved placement practices based on the lessons taken from past experiences and address the failure mechanisms identified in the literature. We also present a set of recommended procedures and guidelines for field application, and lab test results for retained permeability and compressive strength of resin consolidated sand packs. Finally, we present 5 case histories with furan resin system from the Gulf of Mexico as well as statistical information from a total of 25 treatments.
P. 179
Eliminate Formation Damage Caused By High Density Completion Fluid - Crude Oil Emulsion
Authors: Foxenberg William E , Ali Syed A. , Ke Minglie , Shelby David C. , Burman J. W. (Jack) 
Published: December 2007

Abstract
Recent research into clear brine completion fluid induced formation damage, focused on the compatibility of completion brines with formation crude oils(1). Foxenberg, et al., demonstrated that when added to completion fluids, surfactants can provide benefits such as emulsion prevention, surface tension reduction, and aiding flow back of fluid that has leaked off into the formation. They reported on the emulsification tendencies of certain Gulf of Mexico crude oils and high density completion fluids, including calcium chloride, calcium bromide and zinc bromide based brines. Although their work demonstrated a method to eliminate formation damage caused by emulsion, it necessitated disposal of the treated completion fluid. Disposal of the a 12.5 ppg CaCl2-CaBr2 brine was necessary because the fluid supplier was unable to remove the high concentration of solvent/surfactant required to provide crude oil-completion fluid compatibility. This ability to reclaim and recycle a ‘used’ fluid is an essential requirement if these relatively high dollar completion fluids are to be economically utilized.
This paper focuses on the development and application of surfactant based systems that eliminate formation damage caused by emulsification of crude oil and high density completion fluids. Laboratory procedures that ensure efficacy and penetration of the surfactant into the formation matrix are presented. A compatibility matrix of GOM crude oils and completion fluids is included. Field case histories are discussed, illustrating the benefits of specifically designed surfactant systems such as enhanced crude oil-completion fluid compatibility, ability to reclaim heavy brine by reducing the effective concentration of surfactant and diminished risk of environmental exposure by curtailing the amount of mutual solvent required to obtain fluid-fluid compatibility.