bluuebunny/crossref_metadata_2025_split huggingface dataset:
Forecasts and Alternative Analysis for Sulphate Removal or Chemical Treatments for Barium and Strontium Scale Deposition - Offshore Brazil
Authors: Mota R. O. , Bezerra M. C. M. , Rosario F. F. , Prais F. 
Published: December 2007

Abstract
Waterflood projects in oil fields cause important thermodynamic effects in the aqueous phase, resulting in precipitation of insoluble salts due to changes in physical parameters.
Giant fields offshore Brazil are operated by waterflooding. For some of the fields, injection of seawater, rich in sulphates, is not compatible with formation water that contains barium or strontium. Adding seawater to connate or aquifer water leads, during the field production life cycle, to saturation of certain compounds and hence their consequent deposition.
Decision about prevention or remediation of barium and strontium deposition must be attained during the conceptual phase of the field development plan. So, forecasting of the possibility of occurrence of this problem may have a strong impact in the water injection system design specifications and the well completion and interconnections to the floating production unit.
The scope of this paper is to present the results of the analysis conducted to investigate the scale deposition potential in Marlim Leste field, Campos basin, offshore Brazil.
Estimates of intensity of occurrence of precipitation and the critical locations have been conducted in order to obtain the fraction of seawater in the produced brine, which is an important information for evaluation of the problems associated to scale deposition in producing wells.
Based on these simulations economic feasibility studies (CAPEX versus OPEX) compared the alternatives of sulphate removal plants or well treatments with chemicals in order to obtain the final decision of what to implement in this field.
Scale Inhibitors for Co-Deposited Calcium Sulfate and Calcium Carbonate in Squeeze Process in White Tiger Oilfield
Authors: Tung Nguyen Phuong , Phong Nguyen Thi Phuong , Long Bui Quang Khanh , Duy Nguyen Hoang 
Published: December 2007

Abstract
Co-deposition of calcium carbonate and calcium sulfate scale was detected in the some of the wells in the White Tiger oilfield, but, up to now, not much attention has been paid to this problem. In fact, these salts (calcium carbonate and calcium sulfate) co-exist and co-precipitate in the system of seawater and squeeze (injected) water. The mixed CaSO4-CaCO3 scale was found to adhere to a test tube wall more strongly than the pure CaCO3 or CaSO4. More importantly, the treatment of this mixed scale in the field is much more difficult.
This study investigates the inhibition efficiency on mixed scale by using scale inhibitors such as DETPMP, EDTMP, and Lab of Magnetochemistry and Production Chemicals - Institute of Materials Science-NCST) and the chelants such as citric acid, maleic acid and ethylenediamintetraacetic acid. The experimental results show that the mixed DETPMP: MA in ratio 4:1, 1:1, and mixed DETPMP:CA in ratio 4:1; 3:1, and mixed DETPMP: EDTA (2:1) have given the high inhibition efficiency of 98.32%; 93.85%; 96.09%; 96.09%, 92.52% for mixed scale CaSO4-CaCO3 inhibition. These precipitations were analyzed by Scanning Electron Microscopy (SEM). From the SEM photos, it can be observed that for the pure CaSO4 in seawater, the crystals exhibited long needle shape structures (which is typical for calcium sulfate dihydrate) whereas the hexagonal structures were observed for the pure CaCO3 precipitant, which is a typical structure for calcite. In the mixed system, the morphology of CaSO4-CaCO3 crystals changes and spherical shape crystals are predominant. In the presence of the inhibitors, especially with the right inhibitors, the morphology of mixed scale changes and the size of crystals strongly decreases (from 100μm decreases 1-2μm) and are non-adherent. The relation between the inhibition efficiency and the scale morphology for CaSO4-CaCO3 deposits were clearly illustrated.
Old Working Relationship Model Test in a New Location — Integrated Project Management in Western Siberia
Authors: Lischuk V. Y. , Aker H. G. , Bakici M. A. 
Published: December 2007

Abstract
The history of integrated services is a decade old, yet the concept has found new application. A new contract model whereby certain services were contracted to drill horizontal wells on a lump-sum fee basis enhanced the existing relationship between operator and service company. The workscope covered provision of downhole drilling services, tools, and equipment to a maximum total measured depth. Conventional and slim design well options were considered, and equipment specifications were decided to provide flexibility, depending on ongoing reservoir modeling results and production forecasts.
A joint project team consisting of the operator and three principal contractors (namely integrated drilling services, drilling fluids, and rig) spudded the first well in January 2003 with a heavy land rig in the arctic drilling environment. Drilling of the first well with a conventional well design (8 1/2-in. horizontal drain) took longer than initially planned, partly because of high nonproductive time (NPT) that was related to harsh winter conditions, and partly because of workscope changes. However, the second well was finished as the fastest horizontal well drilled to date by the operator, in two-thirds of the scheduled time. Slim-well design, fit-for-purpose equipment and technology selection, improved mud system for intermediate hole sections, and close operational coordination among four participating companies were among the factors resulting in the benchmark performance.
Another key component of the success has been setting of project objectives and targets for quality, health, safety, and environment (QHSE) issues, which were also reviewed by an experienced project startup audit. The review identified critical areas for improvement and thereby facilitated the project's success. The remedial work plan based on the review contributed to the performance improvement in a short time.
A Safe Approach to Underbalanced Drilling in H2S Producing Fields
Authors: Coy Alejandro , Hall Don , Vezza Matt 
Published: December 2007

Abstract
This paper describes a safe and successful horizontal drilling operation on an H2S producing well, using underbalanced drilling (UBD) techniques. The well had been prematurely terminated after using conventional drilling practices that resulted in massive losses and posed the risk of stuck pipe; but, through proper planning, UBD allowed the operator to increase the horizontal length of an existing well. Initial production rates were substantially higher than the rates observed before drilling the UB lateral extension.
The drilling and production results were significant to the future operational potential and viability of this mature field. Equally important was the prodigious success from a health, safety and environmental (HSE) perspective because the field has a 4 percent H2S producing gas cap. Traditionally the industry has been reluctant to use underbalanced techniques in this type of environment.
Located in West Texas, the Yates field was discovered in 1926 and is one of the largest oil reservoirs in United States. Its shallow reserves have been accessed mostly with vertical wells. Over the last few years, implementation of a horizontal well program has made significantly affected on the overall production performance of the field.
The field maintains its reservoir energy by N2 injection into the gas cap and from field-produced water injection below the oil leg.
Low reservoir pressure and highly productive rock in both the gas cap and the water zone present challenges to maintaining underbalanced conditions. These conditions caused wells drilled previously by conventional methods to incur severe lost circulation on encountering a fracture system. The lost-circulation problem resulted in premature suspension of drilling operations. As a consequence, many wells did not achieve long lateral lengths.
This paper discusses the well design and the underbalanced modeling considerations (taking into account detailed reservoir properties). The paper also describes the process used to address HSE issues of the project in the face of the potential presence of high surface of levels H2S while drilling.
Extending the well length underbalanced and intersecting additional fracture sets without losses resulted in an eightfold production increase.
Subsea Rotating Control Head Shop Testing – A Key Step to Assure Subsea Reliability
Authors: Hannegan Don , Bailey Tom , Chambers James 
Published: December 2007

Abstract
Several deepwater drilling-related and environmental issues have dictated a need for the development of a Subsea Rotating Control Head (RCH). Such a tool may also be referred to as a Subsea Rotating Control Diverter. It’s purpose is to effect more precise pressure management by enabling annulus returns containment, diversion, and/or backpressure to be applied on the wellbore in a subsea environment.
Practical applications of such a tool generally fit within the IADC definition of Managed Pressure Drilling (MPD) and include:Alternatative technology to current industry practice of Pumping and Dumping sometimes huge quantities of a heavy viscous mud to the seafloor as a means of overbalancing relatively shallow-to-the-mudline geohazards (abnormally pressured aquifers, gas) when establishing subsea top holes, drilling without a marine riser.For the practice of dual gradient riserless drilling where mud and cuttings may be returned to the rig, this were a subsea RCH diverts returns to a subsea pump.For cost effective riserless drilled exploratory "throw-a-way" or "punch & go" wellbores. Here a subsea RCH with ROV operated choke enables greater wellbore pressure than the mud gradient itself would impart. More precise pressure management is achieved with the pre-selected drilling fluid, resulting in a simplified casing program and deeper open hole.As a component required in a proposed Rierless Top Hole Drilling Package for casing less wellbores when collecting scientific cores in deep water.And, when deployed within a subsea BOP, marine riser, or riser gas handler, function as a subsea annulus barrier, enabling the practice of several variations of dual gradient deepwater drilling.
Given the importance of reliability of subsea equipment in general, shop tests that mimic subsea conditions are warranted. Such test results confirm or otherwise quantify a design’s fitness-for-purpose.
Innovative Remedial Cementing Solution Provides Annular Isolation in Duyong B-4, Petronas Carigali
Authors: Morris Thomas C. , Bidi M. Zuki , Elmarsafawi Youssef , Nair Devan , Said Rifat , Tugcu Reha , Ong Jane 
Published: December 2007

Abstract
Whether a cement-squeeze operation results in an annular seal depends heavily on how far the cement can penetrate and disperse in the fine channels of a partially cemented annulus. In many cases, conventional or microf ine cement slurry will dehydrate and bridge off before it can achieve its objectives. This paper describes the use of engineered, optimized slurry for a squeeze operation in the Duyong B-4 well, which had a perforated zone that demonstrated a low rate of seawater injectivity. This paper also presents the slurry design and properties, execution procedure, and prejob and post-job log evaluations.
After several years of production, gas bubbles appeared in various locations throughout the Duyong field. Shallow seismic showed gas charging in several shallow gas layers throughout the Duyong field. Several wells were investigated as possible contributors to the charging of the shallow sandstone layers, and Duyong B-4 was selected as a probable contributor. Duyong B-4 is a gas well completed in November 1983 with four producing zones. In September 2003, this well was selected as a test well to evaluate the cement quality behind the casing. Both cement bond logs and ultrasonic imaging logs showed gas and fluid channels behind the casing. An optimized cement slurry (OCS) was engineered and tested in the laboratory under the well conditions. Results showed excellent penetration in narrow gaps, optimum fluid-loss control, and low rheology, both at surface and downhole con ditions.
The slurry was used in the squeeze operation; post-job logs demonstrated the success of the treatment. The slurry penetrated the narrow gaps without dehydrating, and good mechanical properties were achieved in short setting times. These properties are especially important in gas-producing wells and they met all the objectives set forth by the client.
The Cement Slurry Inflating External Casing Packer Technology and Its Applications
Authors: He Yurong , Yu Jinling , Liu Qingyou , Hu Qin 
Published: December 2007

Abstract
Lot’s of well-completion challenges face operators to exploit comprehensive reservoirs and old oil field, such as interzonal channeling, up water and bottom water etc. The conventional well completion ways can’t solve them effectively. For example, cementing method couldn’t isolate well for the short interval between layers, otherwise it will contaminate the reservoir, and normal inflating External Casing Packer (ECP) method couldn’t do well for its short life downhole and low isolation pressure. Recent advances in one of the old well-completion ways, namely Cement Slurry Inflating External Casing Packer (CSIECP) technology, will play a key role in meeting these challenges.
This significant technological breakthrough made it possible to inflate several ECPs with cement slurry in one well profile. The CSIECP technology provides permanent and dependable isolation between layers because cement slurry will solidify to be cement stone. So this technology will benefit for producing and later stimulating operation, avoid cement slurry contaminating the reservoir, and raise output.
The Drilling Technology Research Institute of Shengli Oil Field studies this technology and puts it into application firstly in 2002, P.R.China. The technology consists of three key techniques: special tools, high quality cement slurry and advanced process. This paper will give them detailed description including their properties and results of large-scale testing.
In addition to a description of the technology research, the paper will present applications of CSIECP technology in Shengli Oil Field. Some are used to seal thin layer channeling, and some are used as isolation for stimulating operation and producing apart. More than twenty wells’ applications show how this significant technological breakthrough provides cost-effective solutions to several completion problems that have loomed as obstacles to comprehensive reservoir exploitation.
The CSIECP technology is not only an important technical measure to develop thin-bed reservoir, but also one of the effective well completion technologies for extended-reach and horizontal well. It has great economic and social benefits.
Mature Field Re-entries Utilizing Level 4 Multilateral Technology
Authors: Yuan Fucun , Li Wenyong , Durst Doug G. 
Published: December 2007

Abstract
Beginning in year 2000 ConocoPhillips China Inc. has successfully been developing the remaining reserves of the Xijiang fields in the South China Sea through the use of a cost effective low risk multilateral re-entry program. In mature fields with platforms slot constrained multilateral technology provides a solution that allows for full bore access to the lateral while maintaining the value of the existing well bore production thereby increasing ultimate recovery. Through the use of multilateral technology ConocoPhillips gained the additional benefit of minimizing hole collision problems in cluster wells. A very routine level 4 multilateral junction system has been used repetitively and successfully adding value to the overall project. See Fig. 1.Figure 1Primary Level 4 (StarBurst™ system) MLT components
Using Expandable Liners in Deep High Pressure Wells : A Case Study
Authors: Al-Saleh Ali , Al-Kandari Ayad , Al-Fayez Fayez , Brewster T. W. 
Published: December 2007

Abstract
Sabriya 72 (SA-72) is a deep vertical high pressure well originally drilled in North Kuwait in 1983 which was temporarily abandoned due to stuck pipe. The last intermediate casing was set prematurely above the base of a critical highly pressured salt section. Due to the importance of the SA-72 location to appraise a newly discovered field, economics favored re-entering this well in 2003 and sidetracking directionally to intersect suspected fractures in the Jurassic Marrat carbonate formation.
The main challenges of this well were to sidetrack to the target depth without compromising well integrity, and to test the well with the largest production liner possible.
In order to meet these challenges, several first time technologies to Kuwait Oil Company were planned and utilized in this well. These new technologies included running a 6" x 7 ¾" expandable liner, as well as utilizing Near Bit Reamers (NBR), bi-center bits, and slim hole sidetrack techniques to prepare the hole for the expandable liner and to drill to total depth afterwards. An unprogrammed 6" x 7 ¾" expandable patch was also installed in the 7 ¾" production casing to repair a severely damaged area.
Due to unforeseen complications, this is also the first time that the expandable technologies have been used in a 19.7 ppg mud weight. Although the expandable tubulars were run successfully, severe lost circulation after drilling below the expandable changed the course of action and thus the final completion of the well.
This paper will be a case study that discusses the planning, implementation, and lessons learned from the utilization of expandable technology on SA-72.
Pressure Behaviour of a Well Between Two Intersecting Leaky Faults
Authors: Abdelaziz Bensadok , Tiab Djebbar 
Published: December 2007

Abstract
Traditionally if a multiple boundary is suspected in a hydrocarbon reservoir, it is analyzed for its location from the well and its degree of leakage if it is a single communicating fault. Although a well in multiple leaky boundaries presents a very important flow problem in conventional reservoir engineering, no comprehensive method exists in the literature to determine the location of the well relative to each of the leaky boundaries or to determine their degree of leakage and consequently pressure drop caused by these leaking faults in the reservoir.
This study presents a new analytical solution for the pressure behavior of a well near a leaky fault. An extension of the well imaging technique to model multiple leaky boundaries using the new analytical solution which is helpful to generate type curve plots. A study of the pressure and the pressure derivative behavior for a well in multiple leaky boundary systems for different boundaries such as (a) well near a single linear leaky boundary, (b) well between two intersecting leaky boundaries forming an angle of 120°, 90°, 60°.
The solution obtained can be used to improve the design and analysis of both a drawdown and interference tests between the wells separated by partially communicating faults. Type curves generated by these solutions will yield separate estimates of the formation transmissibility and the transmissibility of the fault itself. An explicit solution developed for drawdown at the active well offers the possibility of deriving fault transmissibility from the drawdown and buildup behavior of the active well. This method could be used if a convenient observation well is not available for interference testing. An extension of the well imaging technique allows modeling the leaky boundaries such as two intersecting faults when the well is located any where between them. Pressure and pressure derivative behavior of a well located any where between two intersecting leaky boundaries for different angles shows that the finger print is unique for a determined angle, the location of the well, and the specific transmissibility ratio of the two boundaries.
An accurate correlation between the transmissibility and the maximum pressure derivative has been established and Tiab's Direct Synthesis (TDS) technique is applied to interpret the pressure and the pressure derivative response of a well near a leaky fault. A new parameter, called leakage coefficient, has been introduced to describe a partially communicating fault in case of two intersecting faults. It has been found that the leakage coefficient has direct relation with the transmissibility ratio. Several analytical correlations relating reservoir parameters with the different characteristic points and straight lines in the pressure derivative curve have been developed. Several examples describing the various fault and well locations, fault properties, and angle between the faults are included to illustrate the use of the technique developed.
Analysis of Multi-Rate Test Data Distorted by Wellbore Storage
Authors: Sulaimon A. A. , Omole O. 
Published: December 2007

Abstract
A new method for analyzing multi-rate well test data distorted by wellbore storage is presented. The approach affords a reasonable analysis in the Early-Time-Region (E.T.R) where analysis by the existing models is impossible due to afterproduction and skin effect.
The technique handles variable flow rate by an exponential flow rates solution. Applying the principle of superposition, the additional pressure drop due to wellbore storage was accounted for to provide reliable estimates for the Pressure-Rate-Time-Function (P.R.T.F) in the early time region. A computer package utilizing regression analysis was used to test and validate the model with two field examples.
The assumptions concerning the reservoir and well system are those of the conventional analysis methods that employ the line-source solution.