bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scatter Search Metaheuristic Applied to the History Matching Problem
Authors: de Sousa Sergio Henrique Guerra 
Published: December 2007

Abstract
Reservoir simulation plays an important role in managerial decisions during the life of a reservoir. Thus, it is vital that the simulations present an accurate prospect of real reservoir performance. The main goal of the History Matching (HM) process is to improve the quality of numerical models by contrasting simulated with observed data. A typical HM process evaluates a chosen objective function (OF) comprised by non-linear functions on the uncertain reservoir properties that measure the current mismatch. Thus, the HM problem is a minimization problem where the decision variables are reservoir characterization properties and the goal is to find a set of values for the decision variables that minimize the OF. This paper focuses on the use of an optimization technique called Scatter Search (SS) to perform the HM. The main feature of SS is that it works on a set of solutions called the reference set. The goal is to improve the overall quality of the reference set after each new iteration. New solutions are generated by a non-convex combination of reference solutions.
The proposed methodology was used in both automatic and assisted HM processes and the analyzed reservoir models presented increasing challenges to the algorithm. This paper describes how the HM problem was solved with the SS framework, the expected performance of the methodology in dealing with complex solution spaces and also points how it can be expanded to better scale to a growing number of optimization parameters.
The application of the SS methodology to the HM problem is a recent trend. Unlike most metaheuristics, SS can be effective even when the simulation time of each instance of the problem is long. Most of the current HM methodologies do not perform well when the solution space is both large and complex.
Improvement of Oil Recovery by Jet and Electrical Centrifugal Pumping Technology of Water/Gas Influence
Authors: Telkov Viktor P. 
Published: December 2007

Abstract
Waterflooding is one of the main techniques of oil fields development [1] but this means does not often provide high effectiveness of oil recovery. It comes into particular prominence in the development of high viscosity oil fields when water channels to producing wells and so a great part of oil reserves is not involved in displacement process.
It is known [2, 3] that oil recovery factor can be increased if combined pumping of water and gas is used for oil displacement when the method of water/gas influence is applied. This technique can be used for utilization of associated gas burned in many oil fields the combustion materials of which pollute air.
Nowadays various water/gas influence technologies are known. They are compressor-type technology, uncomressor-type technology, technology using special booster pumps for injecting water/gas mixture (WGM) and technology using jet apparatus. But all these technologies have not gone forward because of their imperfections.
Transient Fluid Flow through Composite Geometries
Authors: de Swaan Abraham 
Published: December 2007

Abstract
The equations describing the transient flow of a fluid with low compresibility through a series of connected porous media with contrasting geometries and/or properties were coupled into one single vector equation. That equation describes pressure and flow velocity at any point in that composite medium and in the Laplace domain. Numerical symmetric transforms are used to obtain solutions in terms of time.
A distinction is made between actual composite geometries in which flow is delimited by actual boundaries in different configurations; and virtual composite geometries, in which flow geometries are observed in pressure plots though no physical boundaries guide the flow.
The formulation was validated through applications to cases presenting composite geometry flow patterns that have been analyzed previously through approaches different from the one presented.
P. 9
An Investigation of Pressure Capacity of Rotary Shouldered Connections
Authors: Winship T.E. , Vinson B. 
Published: December 2007

Abstract
Drill pipe tool joints have been in use for many years. The pressure capacity of these joints has not been a major worry until recently. As hydraulic horsepower increased, higher drilling pressures have been tried. The question of pressure capacity keeps arising. This paper presents a theoretical approach to this problem and presents verification of test results obtained in the laboratory. It is now possible to predict pressure capacity of the tool joints when selecting the drill string for the well.
P. 281
Rotary Steerable System Improves Reservoir Drilling Efficiency and Wellbore Placement in the Statfjord Field
Authors: Andreassen E. , Blikra H. , Hjelle A. , Kvamme S.A. , Haugen J. 
Published: December 2007

Abstract
Drilling in the Statfjord Field has become increasingly challenging as remaining oil pockets require designer wells, horizontal wells, or Extended Reach Drilling (ERD) wells with great demand for reservoir navigation in three dimensions. Until recently this has been performed with steerable motor assemblies, with frequent steering difficulties in the reservoir sands. Low rate of penetration (ROP) while sliding has given an overall low drilling efficiency, and in some cases inadequate steering ability has resulted in a less than optimum wellbore placement. Long sliding intervals have also resulted in poor hole cleaning, which has contributed to stuck drill string and lost circulation problems.
This paper presents the introduction of a rotary steerable system in the multilateral horizontal well C-23 in the Statfjord Field, and how this improved drilling performance over comparable wells in the reservoir.
The following topics are discussed in the paper:–Field description and brief overview of directional drilling challenges in the Statfjord Field.–Statoil's active role in the development of rotary steerable systems.–Functional description of the rotary steerable system, highlighting the technology's benefits compared to traditional directional drilling methods.–Why well C-23 was chosen as a suitable candidate for therotary steerable system, becoming the first successful utilization of this promising technology in the Norwegian Sector.–Case history, emphasizing directional control, drilling efficiency improvement, and other valuable experiences from utilizing the rotary steerable system.
P. 313
Computerized Maintenance Programs: The Drilling Industry Requirements
Authors: Murdoch Ian 
Published: December 2007

Abstract
With the tremendous increase of drilling activity over the last couple of years and the mergers that have occurred, it has become vital that careful consideration be given when choosing computerized software suitable for the Planned Maintenance Program.
The software needs to be simple enough so that Maintenance Personnel are comfortable using the program, and robust enough to operate without software specialist support, particularly when operating on the other side of the globe.
The software has to be flexible enough to encompass the Classification/Certification Societies, Safety Case [D.C.R] and the ever increasing interest being shown by our Customers.
P. 365
New Well Design in the Statfjord Field Utilizing a Multi-lateral Well in Low Productive Zones in the Brent Reservoir
Authors: Njaerheim A. , Breivik A.K.H. , Rovde R. , Kvale E. , Kvamme S.A. , Bjoerneli H.M. 
Published: December 2007

Abstract
The value of multi-lateral well technology is increasing for the Statfjord field. This first cased multi-lateral well was drilled from the last vacant slot on the three Statfjord platforms. At the same time, limiting the production decline is increasingly dependent on successful drainage of remaining oil pockets by infill drilling.
This paper presents a case history covering the drilling and completion of the multi-lateral well C-23 on the Statfjord field. The well was drilled with two horizontal branches in the Brent reservoir, 1765 m and 2394 m long respectively. The two horizontal wellbores both penetrate the Talbert and the Ness formation in the same direction, with a distance between each branch of only 80 m. Both laterals have 7" cemented liners in the reservoir. The lateral has been perforated in the Tarbert formation using a snubbing unit.
The following list outlines the main issues that will be described in the paper:–The commercial and technical justification for drilling a multi-lateral well on the Statfjord field and the technical requirements in each lateral.–Key issues in the planning phase.–The importance of establishing a dedicated team together with the service companies covering all disciplines.–The drilling phase, focusing on general well design, well profile, drilling technology (including the use of a rotary steerable system), runing and cementing of 9 5/8" and 7" liners, as well as time schedule.–Design and requirements for the junction at 2376 mMD. Special emphasis will be put on the most critical phases, including the solid whipstock exchange and re-establishing communication to the main bore.–Running and cementing the 2421 m long 7" liner in the lateral, and the use of a proprietary tough cement.–Completion design and production strategy.
P. 547
Successful Drilling Practices - An Experiment in Cooperation
Authors: Brett J. Ford , Gregoli Mark K. , Gahan Brian C. 
Published: December 2007

Abstract
This paper presents the results of a Gas Research Institute funded study to test the following hypothesis:
"Broad-based benefit is created when drilling organizations systematically cooperate to identify and share successful practices".
To this end, eleven separate Successful Drilling Practices Studies (SDP) were commissioned with the following goals:Identify the most successful drilling practices for each of the study areas;Document these practices in enough detail (in the form of a complete drilling operations plan) to ensure practical application;Disseminate the successful practices; andMeasure the benefit derived from using the successful drilling operations plans.
The studies focus on the following eleven drilling environments:–Greater Green River basin (2 studies: South Moxa Arch Dakota formation and Wamsutter Almond formation),–Arkoma Basin (2 studies: Choctaw thrust and Jackfork Plays),–Cotton Valley Reef Play in East Texas,–Deep Austin Chalk (Texas),–Valverde Basin (Straw and Penn Sands, Texas),–Anadarko Basin (Watonga-Chickasha trend Morrow/Springer formations),–South Texas Gulf Coast (Wilcox Lobo Trend),–Deepwater (Green Canyon Area),–Extended-reach (South Pass Area) drilling in the Gulf of Mexico.
This paper outlines the methodology used to develop these SDP studies, and the benefits reported by operators who have used them. Evidence presented shows that broad-based benefit can be created when drilling organizations systematically cooperate to identify and share successful practices, and that the benefit ranges from 3% to 20% of total drilling costs, with an average benefit on the order of 10%.
P. 603
Conversion of a 1,500-ft Water-Depth Conventionally Moored Drillship Into an Ultradeep Water Dynamically Positioned Drillship
Authors: Vecchio John M. 
Published: December 2007

Abstract
In the late period of 1995 the demand for deep water capable drilling rigs out paced the availability for these units. This trend has continued throughout 1996 without signs of a weakening market in 1997. To meet this demand, fast track and economical solutions were required. This paper examines one solution, the OCEAN CLIPPER project, which began in early 1996 and completed in mid 1997
The OCEAN CLIPPER was a conventionally moored drill ship with 1,500 ft operating parameters, which during this period, was modified to be able to operate in ultra deep water depths to 7,500 ft and beyond utilizing the most sophisticated available technology. Station keeping has been modified to incorporate full dynamic positioning, and state of the art drilling equipment installed. The OCEAN CLIPPER solution represented the fast track economical resolution to this immediate need for the industry. The OCEAN CLIPPER project out paced new-build solutions for delivery at less than 50 percent capital expenditure.
This paper will examine the design and construction factors of this project. An overall schedule, total project cost as well as technical aspects will be discussed.
P. 669
Stopping a Water Crossflow in a Sour Gas Producer Well
Authors: Le Hello Y. , Ghesquiere P. , Woodruff J. 
Published: December 2007

Abstract
This paper presents a summary of the strategy and execution for intersecting and plugging at a depth of 2730m a significant water cross flow (10000-15 000m3/day) invading a depleted sour gas producer well. This operation was performed at the beginning of 1997 in the south west of France. To save time, the top part (0-2100m) of the damaged well was reused and the well side tracked through tile collapsed zone. Then Drilling along side the old well was resumed prior to intersecting the 7" casing and tile 3"1/2 DP. The challenge was also to stop the waterflow and to be able to definitively plug the well with cement.
Included in the presentation of this paper are:–Information regarding the cross flow between a water zone, the Albo Apien formation 2100 m TVD, and the gas reservoir formations 3600m TVD, generated by the collapse of the production casing.–Documents which present information concerning both the planning and execution phases of the project.–Various diagrams of summaries of ranging, milling available tools and their use during the project.–Short video film (5mn) made with a down hole camera showing the collapsed zone, the intersection area and the milled pipes.
This video is unique thanks to the indepth study of the subject and the quality of the images provided.
P. 841
Application and Analysis of Simultaneous Near Bit and Surface Dynamics Measurements
Authors: Macpherson J.D. , Jogi P. , Kingman J.E. 
Published: December 2007

Abstract
Axial, torsional and bending vibrations are all present in a BHA while drilling. The dynamic response of the BHA depends on many variables such as drilling parameters, BHA design, hole condition and inclination, and formation properties. Events such as bit bounce, forward and backward whirl of the BHA and bit, and drillstring resonance can occur during drilling. Some of these events are very detrimental and can cause drillstring component failures, twist- offs, etc.
This paper deals with the analysis of measured drilling vibration data from a field test that used both down-bole and surface vibration measurement devices. Surface sensors included dynamic axial and torsional strain gages and accelerometers, and a single axis magnetometer, all mounted in the drillstring above the rotary table. Down-hole sensors included an axial accelerometer, two orthogonal bending strain gages, dynamic weight on bit and torque strain gages and two orthogonal magnetometers, mounted in an MwD sub.
The analysis described in this paper involves (1) the determination of axial & torsional wave velocities in the drillstring, (2) their use in predicting resonant frequencies, (3) a comparison of predicted and measured resonant frequencies, (4) inference of down-hole dynamics using surface measurements (surface noise cancellation) including a comparison of results with measured down-hole data, (5) an example of the detection of BHA whirl using down-hole data, (6) an example of the detection of bit bounce using down-hole axial data, and (7) an examination of precession of the trilobed bottomhole pattern generated by a tricone bit.
The advantages of using either surface or down-hole dynamic measurements in identifying different drilling problems is demonstrated, as well as the inference of down- hole dynamics using surface measurements. Once drilling dynamics problems are identified, remedial action can be taken to reduce tool and bit failures while drilling, and to optimize the drilling process.
P. 857
Field Validation of a Foam Diversion Model: A Matrix Stimulation Case Study
Authors: Thomas R. L. , Ali Syed A. , Robert J. A. , Acock A. M. 
Published: December 2007

Abstract
Numerous foam diversion models have been developed during the past decade; however, none has been field validated. Field validation of any model used by the matrix treatment design engineer is essential. Without proper validation studies, the engineer cannot optimize the treatment design with any reliability. This paper addresses the field validation of a previously reported foam diversion model incorporated into a matrix treatment design simulator and offers guidelines for diverter selection.
A matrix-acidized well located in the Gulf of Mexico was used for validation of the foam model. In most cases, the simulator's bottomhole treating pressure (BHTP) prediction was within ±5% of the BHTP observed in the well during the foam diversion and acidizing stages. The two-phase, finite-difference simulator models foam flow in the matrix through modification of the relative permeability to gas. The simulator models surfactant adsorption, gas solubility and mineral dissolution with the corresponding permeability changes in a multilayer reservoir. The keys to the foam model validation are good well data and BHTP estimation.
For field validation, a downhole sensor package was used to record the bottomhole pressure and maximize the accuracy of the validation process. Post-treatment evaluation directed at model validation consisted of simulation of the actual treatment followed by a comparison of the simulated and actual BHTP. A detailed description of the foam validation process and the supporting well data are presented. This study indicates that a matrix treatment using foam diversion is not engineered until it is simulated using valid models. Additionally, the study indicates that foam diversion is not the best diversion technique to use in all wells.
Simulations support published laboratory data indicating that poor diversion (equal flow rates per foot) is obtained with foam slugs when a high-permeability contrast and/or damage contrast exist; however, simulations indicate that in most cases good diversion is possible using an oil-soluble resin or foamed acid. Guidelines for diversion type and technique are provided to assist the design engineer.
Operational Experience with Foam-Diverted Acid Jobs in the Gulf of Mexico
Authors: Morphy P. H. , Greenwald K. G. , Herries P. E. 
Published: December 2007

Abstract
This paper summarizes current field experience with remedial acid jobs on "horizontal" wells and long interval vertical completions at South Pass 61 Field in the Gulf of Mexico. Many of the learnings are based on downhole pressure data gathered during the acid jobs. By analyzing this data1-2-3, reasonable conclusions about the effectiveness of the stimulation treatment and foam diversion have been made.
The collection of this data and its analysis are becoming routine in areas where they can clearly be of benefit. This includes new fields, fields with poor stimulation success rates, and fields with large vertical or horizontal wells which require expensive acid jobs. SP 61 is a prime candidate for this type of study because the field has a historical acid job success rate of 11% and twelve horizontal wells, most of which are impaired. Collecting the data has been a profitable venture, since the cost of gathering the data for post treatment review is typically only $2000 to $5000 per job. This is insignificant when compared to the typical $150,000 total cost of a horizontal well acid job with coil, or the cost of avoiding the failure of one large $60,000 bullheaded acid job.
This paper offers two potential benefits. For those with Gulf of Mexico or analog completions, these results may be directly applicable. For others, this is a case study proving the value of evaluating the pressure response during an acid job. This evaluation's impact has been significant at SP 61, and it may be the only way to get data that was not collected during the field's development (e.g. acid's reaction with the mineralogy).
Acidizing Gas Wells in the Merluza Field Using an Acetic/Formic Acid Mixture and Foam Pigs
Authors: da Motta E.P. , Quiroga M.H.V. , Aragao A.F.L. , Pereira A. 
Published: December 2007

Acidizing Gas Wells in the Merluza Field Using an Acetici Formic Acid Mixture and Foam Pigs

Abstract
This paper presents the laboratory testing of acid compositions and the planning, execution, and evaluation of the acidizing operations performed in the Merluza gas field, located offshore Brazil.
Since the beginning of the production, the presence of calcium carbonate scale has been observed. Laboratory experiments determined that the most efficient acid mixture to remove that scale and to clean up perforations was 7% formic acid (HFor)/ 5% acetic acid (HAc) and that the best composition for matrix acidizing was saturated di-sodium EDTA. Regular HCl compositions were not recommended due to the nature of the tubing material (13Cr) and of the high reservoir temperature.
The use of foam pigs to keep the acid at the desired position and to prevent the reaction products from decanting to the formation, and the application of the organic acid mixture to clean up the perforations were very successful, increasing the gas production rate by 740.000 m3/day. Because of this, the matrix acidizing with EDTA was postponed. These results show that Hac/H for compositions are a viable solution to acidize wells where HCl cannot be used, such as HPHT wells, or where production equipment contain chromium.
P. 67
Filtercake Integrity and Reservoir Damage
Authors: Bailey L. , Meeten G. , Way P. , L&apos;Alloret F. 
Published: December 2007

Abstract
Filtercake performance is of particular importance in openhole completions where formation impairment cannot be bypassed by perforation. Emphasis is placed on producing a thin, tough and highly impermeable cake to seal the wellbore during drilling. Once completed and the well is brought onstream, the filtercake is required to break down without the need for expensive clean up treatments. Filtercake integrity can then play an important role in the cleanup of a reservoir. Back production is assumed to cause the cake either to detach from the formation or rupture. Cake-rock adhesion and inherent filtercake strength are therefore important in determining how the cake breaks down to allow oil flow. If the cake-rock adhesion is strong compared to the internal strength of the cake, the cake may pinhole, or blister to allow flow. If it is relatively weak the entire cake may lift off cleanly. This latter case may cause further production problems if the cake subsequently seals the completion hardware.
This paper presents laboratory data on filtercake strength and its relation to cleanup by back-production for typical reservoir drilling fluids. Critical components are identified. The role of bridging solids particle size in determining the balance between adhesion and rupture strength will be demonstrated. Filtercake design to optimize removal through the exploitation of functional weak links will be discussed.
P. 111