bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recovery Of Lost Reserves Through Application Of Underbalanced Drilling Techniques In The Safah Field
Authors: Stuczynski Mark C. 
Published: December 2007

Abstract
In the pressure depleted section of the Safah Field in Oman, use of conventional overbalanced drilling techniques resulted in complete lost circulation of drilling fluid, differential sticking of the drill string and inability to drill horizontal sections.
Underbalanced drilling techniques were successfully utilized to add horizontal lateral sections to existing wells, complete the Shuaiba Carbonate Reservoir waterflood pattern and increase Safah Field production.
Design Considerations in Drill Cuttings Re-Injection Through Downhole Fracturing
Authors: Abou-Sayed Ahmed S. , Guo Quanxin 
Published: December 2007

Abstract
Upstream environmental policies require the use of best available and economically sound technology to continually reduce discharge of mud and cuttings waste resulting from drilling operations. Downhole disposal of mud and cuttings waste through hydraulic fracturing provides a zero discharge solution and eliminates future cleanup liabilities when the loop is closed. This downhole disposal technology has shown success in both onshore and offshore drilling operations and is becoming a routine disposal option of complying with environmental legislation concerning discharges of drilling waste. It also offers favorable economics.
Careful job planning, proper operation design, strict quality assurance and systematic monitoring and analysis are the key to the success of waste disposal operations. Important drill cuttings re-injection engineering design and assurance process are presented in this paper. These include job planning, data required for subsurface geology or formation description and logging analysis, criteria for disposal well and injection zone selection and requirement for slurry rheology quality control. Also presented in this paper are design guidelines for injection strategy selection and injection parameters such as injection rate, batch size, shut-in time required for fracture to close on cuttings, injection equipment requirements, and disposal capacity estimates. Issues related to risk management and commingling of drilling waste injection and produced water injection in the same well are also briefly touched.
Well Delivery Limit WDL: ADCO's Approach to Breakthrough Performance
Authors: Al-Suwaidi Abdullah , Faure Alban , Mukhalalati Talal , Al-Tawil Abdul Rahman , Bamajbour Abdul Rahman 
Published: December 2007

Abstract
The Abu Dhabi Company for Onshore Oil Operations (ADCO) requires a step change in drilling performance to meet its business objectives of increasing production capacity whilst containing technical costs.
ADCO evaluated various performance management systems enabling distinctive drilling performance. The Shell DTL* approach appeared to be the most applicable to the ADCO environment and the most likely to achieve the required objectives.
ADCO is now progressing with implementation of Well Delivery Limit (WDL), a partner of Shell's Drilling The Limit philosophy. This paper describes the WDL process and its step by step implementation plan in ADCO together with results to date.
A kick-off Drilling The Limit workshop was held in January 2000 in Abu Dhabi, organized by ADNOC for their Operating Units (OU's) with support from Shell. Thereafter, ADCO took a leading role as an ADNOC Group OU by developing a three phase implementation plan.
The first phase pilot project was launched in March, 2000 by a three day "Well Delivery Limit" (WDL) workshop.
Based on this initial work, two small multidisciplinary teams of highly motivated and professional staff were formed to implement WDL on two Rigs. The teams were made up of engineers from ADCO's Drilling and Petroleum Development Divisions, Drilling Contractor and Service Companies.
The WDL pilot ran for six months and generated spectacular results, completing some 11 wells in 45% less time than the historical average. Based on the success of the pilot project, Phase-I of the WDL implementation plan was initiated in October 2000, involving a further four rigs working in two different fields.
By June 2001, a total of 55 wells had been drilled under the WDL process in the Pilot and Phase-I stages with outstanding results. The initial success of Phase-I proved that the WDL process could be rolled out to a larger number of rigs without dilution of the results.
In view of this success, a rollout plan is presently underway to spread the well delivery process to the entire ADCO rig fleet of 12 units by mid 2001.
This phased implementation is being pursued in parallel with expanding the WDL multi-functional approach to the conceptual well design phase in order to leverage quality and well productivity improvements in addition to the cost and time savings already realized.
Wall Slip Effects of Water-Based Bentonite Drilling Muds at High Pressures and Temperatures
Authors: Sadeghy K. 
Published: December 2007

Abstract
The effects of wall slip on the reliability of viscosity data obtained using concentric-cylinder viscometers was investigated for water-based Bentonite drilling muds. Viscosity data for a typical mud system (solid content = 8%) were found to depend on the gap width demonstrating that wall slip was occurring. The slip velocity was found to increase with wall shear stress implying that stress-induced migration might be among the mechanism involved in driving the particles away from the wall. At any given wall shear stress, an increase in pressure was realized to reduce wall slip effects but temperature rise was found to make slip effects even more pronounced.
A New and Realistic Approach to Pumping Unit Optimization through the Use of Intelligent Systems
Authors: Hosn Nadim A. , Popa Andrei S. , Popa Carrie Goddard 
Published: December 2007

Abstract
One of the simplest ways to increase production from a well is to optimize the pumping unit. A properly sized and configured pumping unit lifts the maximum barrels of fluid that the well is capable of producing while minimizing the wear on the rods and pump. Optimization is usually done through the use of software such as RODSTAR or ECHOMETER on a well-by-well basis. The user must input all the well parameters by hand, causing it to be a long and tedious process. This makes overall field-wide optimization extremely time-consuming for fields in which there are many wells. Moreover, the software determines theoretically the most optimal unit configuration for the well and may recommend a unit that is not readily available in the area.
This paper describes a new approach for field wide pumping unit optimization. The methodology described here uses a neuro-system consisting of a neural network and an intelligent swapping procedure to find the optimum pumping unit placement for the field. Since field data is used in the model, only pumping units readily available in the field are used. This method is suitable for any field with pumping wells, especially those fields in which there are many wells, thus allowing the selection of a confident data set.
Criteria and constraints are set to select the wells that are currently sufficiently optimized. These wells are used as the model data to train a confident neural network. Optimum pumping unit sizes are then predicted for those wells that are considered to be non-optimized. Finally, an intelligent swapping procedure is invoked to swap over- and under-sized units, thus providing field wide optimization.
The final goal of this study is to provide a tool that allows engineers to set acceptable, realistic criteria to optimize pumping unit size for each well and pumping unit placement on a field-wide basis. The paper presents an example of methodology applicability to a Chevron-operated oil field in California. The proposed procedure provides confident results, great flexibility, and fast optimization.
Nitrogen Coiled-Tubing Fracturing in the Appalachian Basin
Authors: Stidham J. E. , Tetrick L. T. , Glenn S. A. 
Published: December 2007

Abstract
Gas production from the Devonian Shale is attributed to the ability to connect the natural fracture systems that occur throughout the shale. Hydraulic fracturing has long been standard practice, and is required for most shale wells to produce appreciable gas flows. Since the mid-1980’s most operators have used straight nitrogen as the fracturing medium, believing residual water from foam fracturing treatments delays or reduces gas flow from the shale. Nitrogen fracturing, however, increases the difficulty of stimulating multiple zones perforated over long intervals, another aspect of successful shale well completion. Conventional fracturing treatments currently apply high pump rates (&gt;50 MSCF/MIN) and ball sealers dropped throughout the job in an effort to maximize zonal coverage. However, post-frac production logs indicate that some perforated zones do not contribute to the flow. Coiled tubing operations provide a system with which each zone in a multi-zone completion can be isolated, treated and monitored individually. The ease of downhole relocation with coiled tubing allows several zones to be treated in a continuous operation. A broad range of frac gradients has been exhibited in every wellbore treated to date, indicating that conventional treatments will never achieve total zone coverage. While some gradients are so high they cannot be fractured even when isolated, zone coverage has improved by greater than 20% compared to conventional treatments. Early treatments indicate that coiled tubing fracturing offers a slight economic improvement over conventional treatments. Treatment costs have been comparable, while coiled tubing treatments have achieved marginally higher production rates. Results should improve, however, for at least two significant reasons: additional reserves are made available due to improved zone coverage; and job design is in the early stages of development. The importance of rate and volume are being assessed and early indications are that both will contribute to improved economics.
The Successful Use of Polymer-Free Diverting Agents for Acid Treatments in the Gulf of Mexico
Authors: McCarthy Scott M. , Qu Qi , Vollmer Dan 
Published: December 2007

Abstract
The success or failure of a gravel pack or stimulation treatment performed in the Gulf of Mexico (GOM) is often times directly related to the ability of the diverting agent to force the treatment into different portions of the reservoir. Without the success of these diverter stages, entire treatments can be channeled into small portions of these "unconsolidated" reservoirs. Since most damaged intervals are often times the last intervals to be contacted by the acid, the treatment must be chemically forced to attack these intervals early in the treatment to insure proper stimulation and damage removal.
Diversion of acid treatments in the Gulf of Mexico (GOM) have been predominantly accomplished by using either foam, HEC, or particulate matters to "temporarily" block off the zones and force the acid elsewhere. Foam and HEC are the preferred method of diversion due to their "low damaging" characteristics, but are severely hampered by temperature limitations. Foam diversions can also be difficult to control due to foam stability. Although HEC is essentially non-damaging, production can be hindered due to the viscous nature of HEC. Particulate matters such as carbonates, sized salts, and benzoic flakes are not as affected by temperature but can often times be difficult to remove and in some instances impede the production results.
This paper describes the development of a new "solids-free non-damaging" diverting agent based on viscoelastic surfactants. The unique fluid properties of this system allow acid diversions to be tailored to specific well conditions and formation characteristics. By incorporating an internal breaker this system does not require contact with formation fluids, brines, or acids for clean up to provide optimum production. This paper describes the fluid properties at various pH's, temperatures, and salt concentrations along with several successful case histories.
Drill-In Fluids: Identifying Invasion Mechanisms
Authors: Lomba R. F. T. , Martins A. L. , Soares C. M. , Brandao E. M. , Magalhaes J. V. M. , Ferreira M. V. D. 
Published: December 2007

Abstract
Fluid invasion into productive zones has been widely recognized as detrimental to well productivity. Filtrate and solids invasion can cause irreversible formation damage and permeability reduction. Drilling fluids are formulated to avoid excessive fluid penetration into productive zones. Non- damaging acid-soluble solids are usually added to drill-in fluids in order to promote pore plugging and minimize fluid penetration. Also specific polymers are used that reduce fluid invasion due to surface chemistry and viscosity effects. The development of less invasive non-damaging fluid formulations requires the knowledge of filtration mechanisms of solids containing polymeric solutions in porous media.
The work was carried out in two ways: solids with different particle size distributions and concentrations were added to a polymeric base formulation and the filtration behavior of the fluids through unconsolidated porous media was evaluated using computer tomography scanning. Along with the solids investigation, different types of polymeric solutions exhibiting different shear and extensional rheological properties were tested using the same procedure and technique. The extent of the invaded zone could then be measured and the performance of the different types of material could be evaluated.
The results from the lab tests will be used to support the development of a filtration model to calculate filtration flow rates and depth of penetration accounting for non-newtonian rheology and type of bridging agent on filtration mechanism.
Successful Scale Stimulation Treatment of a Subsea Open hole Gravel-packed Well in the North Sea
Authors: Klepaker Jan , Andrews Jamie , Vikane Olav , Hagen Thomas Hille 
Published: December 2007

Abstract
This paper describes the operations and production gains observed from 2 separate scale treatment stimulations in an open hole gravel-packed well (33/9-L-2 H) on the Statfjord Øst Field in the Norwegian sector of the North Sea. This case history is interesting not only in that it describes how sub sea wells can be stimulated for scale deposition relatively cheaply by avoiding rig/boat mobilization but also because it presents data on productivity decline in an open hole gravel-packed well due to scaling. Such completions are generally deemed very robust to formation damage caused by deposition of scaling or fines.
33/9-L-2 H was completed as an open hole gravel-packed well high on the structure in the Tarbert Fm. October 1996 with an initial production rate of 2600 Sm³/d and a PI of app. 800 Sm³/d/bar. Formation and sea water breakthrough occurred simultaneously in August 2000 resulting in a concomitant drop in productivity. This was the first severe productivity drop due to scale (BaSO4) deposition in an open hole gravel-packed well ever observed by Statoil and perhaps in the world wide oil industry?
A combined scale dissolver and inhibitor squeeze treatment was initiated where the treatment was to be pumped through the 6 km methanol service line from the Statfjord C (SFC) platform. The PI had at this stage dropped to 150 Sm³/d/bar. To maximize Barium sulphate load capacity, a two- step dissolver and back flow sequence was designed for. This was then followed by an inhibitor treatment. The volume of the inhibitor squeeze was conservative due to formation damage precautions. The operation was successfully conducted February 2001 in a total of 6.6 days (incl. well L-3 H). The PI increased above its initial value to 1100 Sm³/d/bar. Single well testing revealed an increase in oil rate of 2050 Sm³/d. Due to limiting flowline capacity when all 3 wells were once again on stream, the final collectively obtainable production gain was somewhat less; 1370 Sm³/d.
The treatment effect was relatively short lived and the well productivity decreased to 250 Sm³/d/bar by late May 2001. A second scale treatment was performed in June 2001. The design included the same dissolver sequences as in February, but larger volumes of chemicals were included in the squeeze to extend the effect, and again the well responded very well to the treatment. Post operational testing revealed a PI of over 800 Sm³/d/bar and an oil rate of 4120 Sm³/d. This represented a ‘single well’ - increase of 1270 Sm³/d of net oil as a result of the stimulation operation. Due to limiting flowline capacity the final collectively obtainable production gain was somewhat less (620 Sm³/d) in the L- flowline.
The payback time was less than one week in both treatments performed and gave NPV of respectively 100 MNOK (11.5 MUSD) and 20 (2.5 MUSD) MNOK.
Iron Phosphonate Stabilized Emulsion and Formation Damage During an Adsorption Squeeze Treatment for Scale Mitigation
Authors: Lynn J. D. , Nasr-El-Din H. A. , Hashem M. K. 
Published: December 2007

Abstract
Starting in 1997, calcium carbonate scale was found on gravel pack screens and production equipment in a shallow Saudi Arabian sandstone formation. A campaign of scale control measures was initiated using several types of treatment programs. These programs included forced precipitation, adsorption squeezes, and encapsulated scale inhibitors. These methods have been well described in the literature.1,2 The scale mitigation treatments are preceded by screen de-scaling with HCl.3 The wells are routinely lifted and returned to production to evaluate the de-scaling operations, prior to performing the scale squeeze.
During the first attempt at an adsorption squeeze, using a vendor designed program, the well lost productivity quickly after being brought back to production. The squeeze consisted of three stages: The pre-flush contained surfactants and mutual solvents. The main stage consisted of a 15% by volume of a proprietary scale inhibitor (organophosphonate) chemical prepared in 7-weight% KCl for clay control. The overflush was diesel containing mutual solvents and water-wetting surfactants. The well was shut-in for 96 hours to allow the chemical to adsorb onto the rock surface. Upon being returned to production, the well lost production over the course of several hours and was shut-in.
An investigation into the problem determined that the proprietary scale chemical precipitated iron phosphonate in the presence of high levels of soluble iron. The iron was generated from dissolution of iron bearing minerals in the formation (ankerite, siderite, chlorite, and iron oxides) and during the acid clean-out. More critically, the precipitated iron phosphonate stabilized a tight emulsion that prevented flow of the well. High levels of iron were noted in core floods during vendor-sponsored studies of the chemical, but were not believed to be significant.
A successful multi-staged treatment was designed in-house using HCl and a combination of mutual solvent and nonionic water-wetting surfactants to remove the damage, and return the well to full production capacity. The treatment was applied in the field, and the well successfully returned to production. In the final analysis, the failed treatment can be traced to incomplete evaluation of the reaction characteristics of the squeeze chemical, and incomplete assessment of the environmental conditions of the wellbore, and formation mineralogy.
Development and Application of Insulating Packer Fluids in the Gulf of Mexico
Authors: Javora P. H. , Gosch S. , Berry S. , Pearcy R. 
Published: December 2007

Abstract
Undesired heat loss from the production tubing or uncontrolled heat transfer to outer annuli can be detrimental to the mechanical integrity of outer annuli, reduce the achievable productivity from the well due to deposition of paraffin and asphaltene materials, and contribute to the formation of gas hydrates. This paper presents both laboratory and field data on the development of specialized insulating packer fluids designed to be solids free, non-damaging, environmentally friendly, and highly insulating. Heat losses from produced fluids due to conduction and convection can be reduced by more than 90% when compared with conventional packer fluids. Flow characteristics of the insulating packer fluid system permit the fluid to be easily pumped and placed into the packer annulus, and if ever needed, removed by conventional displacement methods. Field experiences are presented which demonstrate the effectiveness of this system especially when coupled with vacuum insulated tubing.
A Systematic Approach to Improve the Performance of Acid-Fracturing Treatments in Low-Pressure, Low-Temperature Wells
Authors: Kritzler T. , Yaseen M. , Dutta B. K. , Chacon E. 
Published: December 2007

Abstract
A fracturing treatment is defined as treating a formation above matrix rate and pressure, i.e. above the limits dictated by Darcy's Law. Under this condition, the rock cannot take the fluid and is "split" or fractured to accept the fluid at the delivery rate. Several different acid fracturing procedures and treatments are well known and established in the industry1,2,3 and have been used with varying success.
These procedures have been applied to several acid fracturing treatments that were performed on depleted wells in the Middle East. Shortly after the treatment, very high production rates were observed. However, these production rates declined steeply after the initial improvement.
This paper will describe how these treatments were improved with a systematic engineering approach and how production of the wells was quadrupled with stabilized production rates. After initial optimization of the fluids system (such as introducing density-controlled treatments), a core analysis was performed to further optimize acid concentration and chemical loading. The next step involved a buildup analysis to determine fracture half length and skin values. The analysis showed that, even though effective etched fracture lengths were obtained, a positive skin was present in the matrix along the frac length, indicating treatment fluid retention problems due to the low BHFP.
Since foamed acid treatments were not economically justifiable, the readily available gas used for lifting was injected several days before each treatment. The formation was therefore supercharged and able to produce the injected fluid back out of the formation, leaving a negative skin behind.