bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Pseudocases to Interpret P10 for Reserves, NPV, and Production Forecasts
Authors: Murtha James A 
Published: December 2007

Abstract
This article is intended to promote a discussion about how one reduces a lot of data to a few representative values while recognizing what gets preserved and what might be lost. Specifically, the phrase, "P10 production forecast" is shown to be ambiguous. By acknowledging this ambiguity and asking the intended use of the values, we examine some possible definitions and illustrate them with examples. The same scrutiny is then applied to P10 values for reserves and NPV, which are presumed to be unambiguous. Although raising more issues than it answers our goal is to open or expand the dialog and to suggest some alternate procedures. Managers as well as analysts need to understand the ambiguity presented below so they can ask better questions and make more informed decisions.
Key Environmental Performance Indicators in Drilling Operations
Authors: Paulsen J. E. , Saasen A. , Jensen B. , Grinrød M. 
Published: December 2007

Abstract
There is a trend in performance reporting within the oil and gas (O&G) industry that gains increased importance. External stakeholders with different motives have put increased pressure on the O&G industry asking for data that facilitate audit of an O&G operator’s ability to deliver sound environmental performance. Following this the question of relevant performance indicators emerges. This paper presents documentation on how a holistic approach to performance planning and measurement in drilling operations helped develop practices that resulted in improved cost-effectiveness and less environmental burden. Key performance indicators were used extensively for trend-analysis and management purpose. The methodology used rests on transparency, commitment from all involved personnel, and meets the need for better performance reporting routines for a drilling operator. Waste is one of several Key Environmental Performance Indicators (KEPIs) that aspire to be included in forthcoming common global reporting routines in drilling operations. The approach used in this case, Total Fluid Management (TFM), addresses all aspects of drilling efficiency and waste generation in drilling operations, to resolve a holistic compromise that is considered to be a sustainable practice.
Data collected through a period of 20 months after implementation of the TFM is presented. The data substantiates that costs associated with drilling and completion fluids and associated waste generated have been reduced significantly compared to the period before the implementation of the concept. The environmental load has been reduced accordingly. All benefits have been achieved without compromising the profit of the fluid suppliers. The holistic approach in planning facilitated this mutual beneficial outcome. It is argued that the model is progressive to the extent that it challenges current practice and forces the contracting industry to think and plan differently. It is claimed that the data acquisition methodology and the reporting format of the TFM allow transparency for external audit purposes
Intelligent Internal Gas Injection Wells Revitalise Mature S.W. Ampa Field
Authors: Lau Hon Chung , Deutman Robert , Al-Sikaiti Salim , Adimora Victor 
Published: December 2007

Abstract
In February 2000 BSP drilled and completed its first internal gas injector in the SW Ampa Block 11 field. Well SWA-285 causes deliberate crossflow of gas from the deep AW/AX gas reservoirs into the gas caps of the overlying AV oil reservoirs (Fig 1). The result is a pressure maintenance scheme that does not require any surface facilities. New production technologies employed (including long openhole gravel pack, surface-controlled interval control and lubricator valves and permanent downhole gauges) allow both control and monitoring of the downhole gas injection scheme. After 17 months of injection, the increase in AV reservoir pressure recorded in a number of observation wells and the favorable production from downdip wells in both easten and western flanks have confirmed that the internal gas injection is yielding the desired results. As a consequence of these encouraging results, a downdip horizontal well was recently drilled to capture the benefits of the first internal gas injector. In addition, a second internal gas injection was recently drilled in an adjacent block (Fig 2).
Minimizing Formation Damage with a Reversible Invert Emulsion Drill-In Fluid
Authors: Green T. C. , Headley J. A. , Scott P. D. , Brady S. D. , Haynes L. L. , Pardo C. W. , Dick Mark 
Published: December 2007

Abstract
A reversible emulsion drill-in fluid can exhibit the drilling benefits of conventional oil-based emulsion muds and still show cleanup characteristics equivalent to or better than biopolymer calcium carbonate water-based drill-in fluids. After exposure to the reversible emulsion drill-in fluid and an acid cleanup procedure, laboratory tests have demonstrated satisfactory retained permeabilities through sandstone cores in both the production and injection directions. Tests on aloxite disks show that the reversible invert emulsion filter cakes are stable during displacement of the drill-in fluid with brine. Clean up of the filter cakes shows that the destruction of the reversible invert emulsion filter cake containing calcium carbonate is easily attained with acid treatment through a simulated gravel pack.
The reversible emulsion drill-in fluid had higher retained permeabilities in both the injection and production directions when compared to the xanthan-based calcium carbonate fluids. The cleanup treatments for the reversible emulsion fluid and the xanthan carbonate fluids varied from a 10% acetic acid solution to a 10% hydrochloric acid solution. Tests of the reversible invert emulsion drill-in fluid filtercake stability on aloxite disks in a stirred filtration cell showed that the filter cakes are quite stable to calcium chloride displacement brine. Placement of gravel packing sand over the filter cakes and subsequent clean up of the filter cakes through the gravel pack showed that good clean up of the cakes could be achieved through the pack.
Lab work presented here has been validated by application of this reversible emulsion drill-in fluid in West Africa, where both production and injection wells have exceeded what was expected from use of a conventional invert emulsion. In addition, the wells were completed with less rig time and lower cost for the completion and clean up.
Use of Corrugated Material Technology to Provide Low-Risk Solution to Repair Connector Leakage on the Captain Field, UKCS
Authors: Smalley Michael T. , Rae Graeme , Heiskell Wes 
Published: December 2007

Abstract
The Worlds’ first successful installation of a newly developed Thru Restriction Expandable Internal Casing Patch (TRECP) system has been completed in the North Sea in Texaco's’ Captain Field. This TRECP system uses expandable liner technology to provide a hydrostatic seal for casing connectors, couplings and perforations. The system incorporates a corrugated liner capable of being run through a restriction and then smoothed out to a larger diameter in the casing or riser, using a cone and a hydraulically expanded collet. As a result, the overall process of creating the sealed area is simplified and the associated risk minimised. The TRECP was used successfully to isolate a leak in the squinch connector due to an ‘O’ ring failure.
In this paper, the authors will discuss the development and testing of the Thru Restriction Expandable Casing Patch and present an engineering explanation and operational description of the system. They will outline the original requirement for the TRECP, how the system was installed and operated, including the difficulties encountered, how wear on the TRECP was addressed, and how lessons learned from the first installation are being applied to improve the performance and process in future applications. The authors will also explain how the service company and operators worked together to finance this TRECP system such that it could be proven in a low cost, low risk environment prior to application in very high cost, high risk, environments.
First High Pressure, High Angle Well in Kuwait: Case Study of WMN-2
Authors: Al-Saeedi M. , Munger R. , Tooms P. , Al-Mutairi B. , Al-Quraini K. , Decaire J. , Tuncer T. 
Published: December 2007

Abstract
Drilling high angle wells into a heavily fractured, highly pressured, sour Jurassic reservoir may be the key to unlocking substantial reserves of light oil for Kuwait. One of the main risks to effectively developing this unconventional reservoir is the ability of wells to access a permeable, interconnected, vertical fracture network, without which the oil will not flow. Less than 50% of the vertical wells drilled to date have been successful due to a failure to intersect fractures or due to formation damage suffered during drilling. High angle or horizontal wells, while more technically challenging and expensive, will ensure fractures are encountered and will ideally penetrate multiple large, oil bearing fractures, to provide high productivity and reserves recovery per well. This paper discusses the challenges of designing a high angle well into the Jurassic which has so far proved difficult to drill vertically. These challenges can broadly be divided into three major categories - the high pressure nature of the well, the directional challenges imposed by the high angle in the reservoir, and the metallurgy aspects of operating in a highly corrosive environment.
The approach to coping with the high pressures (12,500 psi at 12,500 ft) has been to combine local experience with some of the learning from other parts of the world, notably HPHT drilling in the North Sea. The prediction of a pressure window in which to operate without gains or losses has been generated by analyzing local offset data. The task of staying within that window is crucial to being able to cross open fractures and was aided by utilizing the latest drilling technologies such as Pressure While Drilling (PWD).
Directional planning again builds on local knowledge to evaluate different options for achieving the objectives of the well. The latest tools and technologies was required to meet some demanding angle build rates in the lower part of the well in hard rock and through large open fractures. Experience gained in other parts of the world was used as the basis for design since there is no prior application of the technologies in Kuwait.
The presence of high concentrations of H2S and CO2 (5,000 – 20,000 ppm & 10,000 ppm respectively) at high pressure has made the metallurgy design a task of finding a way to resolve the conflicts between designing for high pressures, longevity, high levels of H2S and staying at reasonable cost. The final design has achieved a satisfactory balance by using risk assessment to minimize the use of expensive alloys.
This was the first well of its kind in Kuwait and could pave the way for the exploitation of a very substantial volume of light crude oil.
Innovative Well Completions in Gulf of Suez Fields, Egypt
Authors: Fotouh Mahmoud Aboul , Gutleber D. 
Published: December 2007

Abstract
Drilling and completing wells quite often encounter unexpected events during routine operations. Troubles occur that many times are easy to resolve while other times are more difficult and can completely turn the plan upside-down. Adapting the course of action to still meet well objectives involves many factors and individuals, incorporating innovative techniques and new technologies without compromising safety or environmental implications. This paper will discuss four case histories, which are examples of how well completion programs were modified due to unexpected events in order to salvage the well’s production potential. Coordinated teamwork between drilling, production, reservoir, and geoscience personnel to establish a revised plan in a timely manner, responding to operation/reservoir complications, is the key to success. Some of these creative alternatives were derived based upon specific well characteristics and are uncommon in normal operations. However, by sharing these techniques, others may be able to benefit from GUPCO’s key learning’s and respond to complications in their own operations.
New Incentive Contract Achieves Improved Performance in Oman
Authors: Roes V. C. , Hopkins C. J. , Young T. 
Published: December 2007

Abstract
Incentive contracts for drilling rigs and services traditionally follow a "beat the curve" approach aimed at reducing well durations. This method failed to achieve breakthrough performance with the PDO Deep Oil and Gas exploration drilling team in Oman. By developing a strategy that approached the supply of drilling goods and services using a team approach, and implementing an incentive scheme to reward the team as a whole rather than individual contractors, a significant improvement in performance was achieved. Exploration drilling costs were demonstrated to be reduced by 32% over the first two years of contract inception, resulting in significant savings for PDO and improved goods and services from the service contractors.
Risk Mitigation Technique for Advanced Rig Control Systems
Authors: Murray D. , Montgomery D. , Florence F. 
Published: December 2007

Abstract
An advanced rig control system that was provided to a major international land drilling contractor streamlines the ergonomic tasks that are routinely performed by a driller. The system employs joystick controls from a specially designed console with touch-screen displays that eliminate conventional SCR and drawworks control panels. Signals are routed though industrial grade computers and robust programmable logic controllers (PLC) to integrate data and control to simplify the correct operation of the rig. An electronic automatic driller is used to optimize drill line payout with up to four selectable constraints chosen by the driller and/or drilling engineer.
Maintenance of the software can be achieved from a remote command station via a telephone or satellite connection. The PLC and user interface software code can be monitored and modified if necessary. Using a data logger that records and transmits PLC parameters, the system designers can verify that the driller is using the system as intended.
While this remote connectivity provides high system reliability, it can increase operating risk unless proper procedures are followed. This paper identifies the risk factors and recommends specific policies to mitigate these risks. Specific examples are cited where the software on a working rig was modified from a remote site.
Lessons Learned from Acid Pickle Treatments of Deep/Sour Gas Wells
Authors: Nasr-El-Din H. A. , Al-Mutairi S. H. , Al-Driweesh S. M. 
Published: December 2007

Abstract
Pickle treatments are commonly conducted to remove various contaminants from the wellbore prior to performing chemical treatments in various wells. Introduction of these contaminants into the formation during the treatment can cause loss of well performance, especially in tight formations. These treatments should be designed to remove various contaminants from well tubulars in an efficient and cost effective way.
A pickle treatment was designed to clean well tubulars in several wells prior to performing acid fracturing in the carbonate formation. The pickle treatment consisted of several fluids such that each fluid removed one type of contaminants. This paper examines the effects of fluid composition, volume, and placement (bullheading versus coiled tubing) on the efficiency of pickling treatments. More than twenty pickle treatments performed on deep, sour, hot gas wells were examined.
To assess pickle treatments in the field, spent acid was analyzed and the concentrations of key ions were measured. Sufficient measurements were made to obtain concentration profiles of chemical species in the spent pickle acid. These profiles were numerically integrated and the data were used to assess the outcome of each pickle treatment. In addition, particulate solids present in the spent acid were separated and analyzed using XRD and XRF techniques.
Pickle treatments were conducted on more than twenty gas wells. Some of these wells were perforated, while others were not perforated. Un-perforated wells were pickled using 1.75" high-pressure coiled tubing. On the other hand, perforated wells were pickled using bullheading. The pickle treatments consisted of slugs of surfactants, organic solvents, hydrochloric acid and gelled fluids. Samples of all pumped fluids were collected and analyzed. In addition, well flow back samples were collected every two minutes and were also analyzed to determine their composition.
Analysis of spent acids indicated that the major tubular contaminants are mill scale and pipe dope. Spent acid samples collected from deep sour gas wells contained up to nearly 105,500 mg/L of total iron. The efficiency of removing pipe dope was followed by tracing the concentration of zinc, the main acid-soluble constituent in the pipe dope, in the spent acid. The concentrations of acid and iron were used to determine acid reaction with the corrosion products present in the tubing. The concentration of the chloride ions was used to determine the dispersion and mixing behaviour of the acid slug.
This paper presents the results obtained from analyzing more than 2000 samples obtained from twenty treatments. The results of this work have been used to enhance the efficiency of the pickle treatments and to significantly reduce the treatment cost.
Modified Synthetic-Based Reservoir Drill-In Fluid: Eliminating the Need for Costly Synthetic Displacements
Authors: Luyster M. R. , Sketchler B. C. , Ali S. A. , Foxenberg W. E. , Dick M. 
Published: December 2007

Abstract
A number of technical advances in the design and engineering of oil- and synthetic-based reservoir drill-in fluid (RDF) systems have taken place in recent years. This includes modifications to the emulsion/wetting package, type and size of the bridging/weighting material and displacement techniques. This paper presents laboratory analyses and subsequent field application of a newly formulated RDF compatible with a sand-control-screen completion.
Through laboratory testing, an emulsification package was identified that would enhance filtercake lift-off. Next, a pilot yard test was performed utilizing a desilter to optimize the D50 of the bridging/weighting material. A unique combination of nozzle, hydroclone and pump pressure was utilized as the combination of these three variables yielded a D50 of less than half the original D50. Laboratory tests confirmed that a filter cake deposited by this modified synthetic-based RDF could effectively "flow" through a selected sand-control screen.
The authors also show how the combination of specifically sized weighting/bridging material, the emulsification/wetting package, and custom completion practice to run the premium sand-control screen eliminated the need for a costly solvent-based displacement. In addition, production data from the subsequent Gulf of Mexico horizontal completion that successfully utilized this technique will be provided.
Productivity Preservation via Hydraulic Propped Fractures in the Eldfisk North Sea Chalk Field
Authors: Cook C. C. , Brekke K. 
Published: December 2007

Abstract
The Eldfisk oil field is a high porosity, low permeability reservoir of soft chalk in the Norwegian North Sea. Commercial oil production from the Eldfisk field is dependent on well stimulations involving hydraulic fractures. To date, pseudo limited entry (PLE) acid fracturing has been the standard completion technique that initiates relatively high (5000 bopd) individual well oil production rates. Over time however, many of the Eldfisk wells have experienced rapidly declining oil production. The main causes of the decreased well productivity are attributed to hydraulic fracture closure, solids production and casing collapse. Initial calculated skin values of–4.5 on average increase annually at a rate of +0.6. Through year 1999 over 100 casing deformations have been logged in the reservoir. The root problem behind the productivity deteriorations is the Eldfisk field soft chalk nature where the Brinell Hardness Number (BHN) is commonly less than 5 for the most productive zones. In late 1997, an alternative completion technique involving four hydraulic propped fractures was successfully executed in a horizontal well. Evaluation of rate-time flow efficiency for the propped fractured well versus acid fractured wells with the use of an analytical model is reported in this paper. In addition, the analytical model is used to run predictions of increased multiple propped fractures. This paper relates formation BHN to the hydraulic fracture design criteria and concludes that productivity for hydraulic propped fractured wells in soft chalk formations is preserved over time to a greater extent versus the current standard PLE acid fracture technique. This paper concludes that an additional horizontal well with eight hydraulic propped fractured zones is warranted to improve understanding of the cost effectiveness of this alternative oil recovery completion technique for the Eldfisk chalk field.
Asphaltic Crudes and High Density Brines: A Potentially Lethal Combination
Authors: Luyster Mark R. , Hebert Paul , Ali Syed A. , Kippie David P. , Carboni John A. 
Published: December 2007

Abstract
The use of high density brines in well completions and/or recompletions poses potential problems for initial well production. Emulsions may be formed when the crude and completion brine are commingled under high shear at points such as the perforations, well-head, chokes and valves. This commingling can lead to the production of very stable viscous brine-in-crude emulsions. Resolving emulsions can be a costly operational problem, especially in sub-sea completions. With heavy or asphaltene bearing crudes, the prevention of emulsions is even more challenging. The resulting emulsion may likely be stabilized by asphaltene precipitates. This can lead to very viscous and tight pads. These emulsions and/or pads can yield a multitude of operational problems that include: increased shorting in the separators, tripping of equipment, costly clean-up/disposal, and increased completion delays/costs.
This paper describes laboratory analyses that were utilized to evaluate six (6) emulsion preventers to prevent a potential asphaltene-stabilized emulsion. Crude recovered from well tests in a recent Gulf of Mexico deep-water discovery were analyzed for composition. These crude samples were then commingled with high-density completion brine that was treated with various concentrations of selected emulsion preventers. The results were evaluated for clarity, presence of a pad, coalescence, and emulsion tendency.
Emulsion preventers are specialized chemicals that rely on a soluble carrier. They must be brine soluble and this alone may pose a challenge in high-density brines. They must remain in the brine phase under downhole conditions and present themselves at the crude-brine interface, thereby, initiating the coalescence process.
To simulate downhole conditions as near as possible, iron was introduced into the completion brine at various concentrations. Iron alone can cause and/or augment the severity of an emulsion. In some cases, reverse emulsions were evident. All emulsion preventers were tested in the presence of iron as a final evaluation of their performance.
This study allowed the authors to introduce a new emulsion preventer for use with high-density completion brine. This non-emulsifier was utilized in four (4) recent deep-water sub-sea completions in the Gulf of Mexico and yielded favorable results. The field case histories are presented to substantiate the laboratory findings. An additional benefit derived from this study was a more efficient and rapid well clean-up after the initial completions with no system upsets.