bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Experience To Assess Efficiency of Scale-Dissolver Treatment in a Subsea Deepwater Well
Authors: Daher J. S. , Gomes J. A. T. , Rosário F. F. , Bezerra M. C. , Amorim V. C. F. , Dumas G. E. S. , Oliveira E. A. P. 
Published: December 2007

AbstractThe objective of this paper is to present how Petrobras is successfully managing production losses due to mineral scale formation in subsea production wells from its biggest offshore field1.Marlim Field, discovered in 1985 with a STOIIP estimated at 1,012 million STD m3 (6,369 million STB) and a field area of 146 km2 is located in water depths ranging from 600 m to 1100 m.Current Marlim Field production, around 446,754 bpd is supported by injecting 761,971 bpd of sea water. The water production is 217,150 bpd (water cut = 32%) and GOR is 82 STDm3/STDm3. A total of 117 wells are on operation, with 73 producers and 44 water injectors. The field was developed using subsea completion through the vertical, deviated and horizontal wells, equipped with cased hole and open hole gravel packed screens.Scale formation has occurred as a consequence of the incompatibility between the barium and strontium present in formation water and the high amount of sulfate in the injected seawater.To avoid production losses a plan of water management was implemented, including frequent produced water chemical analyses to investigate the convenience for applying a chemical bullhead treatment to remove scale in the production wells (tubing, screen, gravel pack and near well bore)2,3,4.This paper presents results from dissolver treatments performed in the field and also from a special investigation using a rig in a horizontal well. Valuable information was obtained in this intervention, clearing up the scaling occurrence phenomena in this scenario, allowing therefore an improvement on productivity recovery of the wells.
Data Analysis of Barnett Shale Completions
Authors: Grieser B. , Shelley B. , Johnson B. J. , Fielder E. O. , Heinze J. R. , Werline J. R. (Rusty) 
Published: December 2007

Abstract
The north Texas Barnett shale illustrates successful commercialization of an unconventional reservoir. However, it took 17 years to evolve from pumping crosslinked gel (XLG) carrying more than 1 million pounds of proppant per job to slick water fracs (SWF) consisting of large volumes of water and small quantities of sand. This transition to SWF stimulation opened the door for widespread development that has advanced the Newark East (Barnett shale) to the largest producing gas field in the state of Texas.
This paper investigates Barnett completion strategy during the time period from 1993–2002. The 393-well dataset includes completion, reservoir, and production data. Unique data visualization tools were used to investigate various completion parameters and their effect on production.1
This unbiased look at a large block of data challenges some of the preconceived opinions about Barnett shale, including:
The Barnett shale is a continuous/homogeneous formation yielding commercial production in all instances. XLG fracture stimulation is damaging to the Barnett, and SWF always outperform XLG fracs. High rates and large volumes of fluid and proppant always give higher production. Reservoir quality is unimportant or has a negligible effect on production outcome. The effect of changes in stimulation variables on production is readily apparent.
We found that production results show a broad scattering when crossplotted with various completion and reservoir inputs. This result is not uncommon when analyzing field data. The large number of variables and scatter within the data required the use of data clustering techniques to extract useful information. Advanced data mining techniques were used, including self-organizing maps (SOM) to reduce the statistical noise and highlight completion and reservoir parameters directly affecting production. The results show a production outcome based on reservoir quality and completion strategy.
Collaborative Decision Making in Operations-Centre Environments
Authors: Taylor D. , Fosse K. 
Published: December 2007

Abstract
The oilfield of the future vision, as pursued by almost all of the oil and gas majors, has wide-reaching implications for the way that the industry operates that go beyond mere technology implementation. To date the industry has focussed on the acquisition and transport of data to decision makers so as to capitalise on the opportunities to optimise productivity, efficiency and recovery of the field. However, attention is turning to those decision makers and the tools, methods and work processes that will support their activities. Of particular relevance to this debate is the role of collaboration and the ways in which integrated multi-functional teams can work together to make better and faster decisions.
In an effort to gain better insight into the potential benefits from working in such new collaboration environments, Chevron, Hydro and Shell decided to sponsor a Joint Industry Project with Epsis and SAIC. This project has been set up to analyse and test central topics related to operation centres for Production Optimisation, using the facilities of the Epsis Operating Centre Environment.
This paper defines what is meant by collaboration in the context of Production Optimisation and discusses the various forms of collaboration, physical and virtual, that are possible. It also sets out a framework in which to evaluate the extent to which collaboration can be used in work processes and decision scenarios. This framework is the starting point for the analysis and re-design of work processes and the paper presents an approach to how work processes might be tested within an operation centre.
It is recognised that operation centres will be significant developments within the organisation and will affect both people's work habits as well as have an effect on organisation design. The paper presents some of the challenges associated with implementing these facilities and associated working practices and some of the solutions that organisations may adopt to help manage these changes.
When are we Going to Address Organizational Robustness and Collaboration as Something else than a Residual Factor?
Authors: Hepsø V. 
Published: December 2007

Abstract
We see an increasing acknowledgement of the importance of work processes and change management in e-field initiatives. However, it is argued in this paper that the E&P business in general tends to lack a framework and the concepts to approach the social nature of work and collaboration. Several studies show the challenges of realizing global concepts, standardized work processes and seamless integration of data. The paper discusses how the social nature of work must be addressed. It also shows what a more open-ended understanding of the work practices of subsurface professionals’ can mean for "intelligent energy". Seven propositions based on an understanding of integrated collaborative environments as information ecologies are set up and presented using examples from ongoing e-field/integrated operation projects. The work practices presented are from the subsurface and production optimization domain. Examples are from Statoil, using my company as an example of an industry that has particular work practices also found elsewhere in the business. This kind of work is knowledge intensive, highly dependent upon information and communication technology for the retrieval and presentation of data and information. A shared understanding among professional subsurface and petroleum engineering professionals of this information is enabled with the help of primary and articulation work. These two types of work enable communication, collaboration and decision making. Finally, in the conclusion some suggestions for development work within integrated collaborative environments based on the propositions will be presented.
An Offline Approach Utilising New Slickline Technology
Authors: The Giang Ha , Dinh Ngoc Tran , Flores D. , Wendlinger F. 
Published: December 2007

Abstract
The oil and gas industry continuously strives to develop tools and techniques to meet and exceed operational objectives with less cost. These efforts have brought about advancements in downhole tools that enhanced slickline technology, making it a more versatile means of providing accurate depth measurement so that more complicated services can be performed1. Likewise, development of slickline deployed inflatable packers also exemplifies the on-going industry endeavors to conform to a business model that simplifies costs, operations, and logistics2.
This case study involves work done on the Rang Dong Oilfield located 160 kilometers offshore S.R. Vietnam. In operation since 1998, this field has produced oil and gas from sandstone and granite basement reservoirs since 1998. In all four existing wells in this field that were studied, a workover campaign was performed to install gas lift valves because of declining reservoir pressure. To prevent formation damage while pulling the existing completions and running the new completions, with gas lift mandrels, isolation plugs were chosen to isolate the producing intervals. This technique was used because of its ability to minimize rig time by working offline and because the plugs could pass through a small restriction and set in the tubing joint of the tail pipe without requiring a landing nipple profile.
The innovative techniques for well workovers used in this project utilized slickline deployed inflatable technology to provide economic alternatives traditionally reserved for more costly options. Borrowing from computer age terminology, this approach is know as the "offline" approach which conveys the meaning that well preparation work takes place before the rig is placed on location. As implemented, the plug isolated the formation from kill weight fluid before the rig was needed so that production tubing could be removed and reinstalled with gas lift mandrels. The use of this method reduced rig cost by an average of eighty-four hours per well and realized a savings of $2MM for the entire project. Not addressed in this report is the incremental revenue generated by eight additional days of early production achieved by completing the project ahead of schedule.
Transient Simulations Assist Hydrate Remediation Efforts in Deepwater Gulf of Mexico Dry-Tree Wells
Authors: Harun A. F. , Krawietz T. E. , Erdogmus M. 
Published: December 2007

Abstract
Hydrate plugs were formed above the mud line in three dry tree oil wells in the Gulf of Mexico. One plug was formed during slick line operations that caused the tool string to get stuck at ∼3000 ft (above the mud line) while pulling out of the hole, even though the well was believe to have been freeze protected with LDHI. The other two plugs were formed when trying to open the downhole safety valves by pumping crude to return the wells to production after they were shut-in due to hurricane evacuation. Several unsuccessful attempts to melt the hydrate blockage included pumping methanol through a chemical injection line below the plug and lubricating in glycol above the plug. As a last attempt, before utilizing coiled tubing, injecting hot oil into the tubing-casing annulus was considered. Transient simulations were performed to determine the required injection temperature, rate, and time. Well integrity issues were mainly associated with the compatibility of hot oil with elastomers and possible asphaltene or paraffin precipitation in the annulus. The tool string came loose after 12 hours of hot oil injection. The hydrate plugs in the other two dry tree wells melted after 6 and 60 hours of injection time, respectively. The slick line operation was reviewed and recommended practices were put in place to prevent future hydrate blockages. A revised restart procedure has been implemented to eliminate the hydrate problem in future startups.
Permanent Plug and Abandonment Solution for the North Sea
Authors: Liversidge D. , Taoutaou S. , Agarwal S. 
Published: December 2007

Abstract
The numbers of ageing fields in North Sea are only increasing as more and more brown fields are reaching end of productive life. The challenge today in the North Sea is to maximize production from what remains and also to safely, economically and optimally abandon the wells, which can no more produce. The operators have hence started looking for options to abandon wells in a highly government regulated environment.
Permanent Plug and abandonment is done with the objective for the well to be sealed and isolated forever. This long term sealing requirement is one of the principle parameters to measure the success of abandonment. This becomes even more critical in the North Sea as the cost of operating offshore and risked cost of returning to re-abandon a leaky well run into millions of dollars. Furthermore the environmental liability of cleaning up slicks from a leaky well is also a concern. Technically sound abandonment practices are necessary for long-term isolation to protect the environment and to avoid the eventuality of an expensive re-abandonment.
This paper presents
A discussion of abandonment regulations and requirements. A case history for permanent abandonment campaigns in the North Sea region UK sector. A discussion of the methodology, materials and techniques used.
Experience in AA-LDHI Usage for a Deepwater Gulf of Mexico Dry-Tree Oil Well: Pushing the Technology Limit
Authors: Harun A. F. , Fung G. , Erdogmus M. 
Published: December 2007

Abstract
A dry tree oil well in the Gulf of Mexico (GoM) was producing water cut above 50 percent that prohibits the usage of the existing anti-agglomorate low dosage hydrate inhibitor (AA LDHI) during extended shutdowns and cold restarts. However, by using the concept of cumulative water cut, defined as the ratio of cumulative water production over the cumulative liquid production, and implementing the strategy to outrun the water during warm up time, the well has been put back on production without any hydrate problems. Thus, understanding the well performance, using the right analytical tools, and challenging the technology limit through creative thinking have enabled the operator to manage the hydrate risk and operate the well at minimum cost.
The Importance of Well Construction and Well Integrity for Reservoir Management— A Mature Field Experience in Sudan
Authors: Tewari Raj Deo , Raub Mohd Razib Bin Abd , Omar Mohd Ismail , Fenghan Bai , Moris Munir , Jelani Jamil , Ramachandran Supra , Fooks Andrew Leslie , Peden James M. , Montague E. 
Published: December 2007

Abstract
This paper describes the importance of well construction & well integrity and its relationship to reservoir management. Productivity enhancement studies in combination with reservoir simulation modeling on the Greater Heglig fields have revealed that well performances and production related problems were largely related to poorly designed wells and poor cementing practices. As a result, water channeling and cross flow across wellbore dominated true well performance characteristics contributing to very high water cuts in the majority of the producers in Greater Heglig fields. Separating the mechanically induced well behaviour from reservoir behaviour helped history matching the wells greatly, findings of which were subsequently validated during the study through running of ultra sonic imaging tool. The ultra sonic logging campaign proved the existence of channels, micro annuli's and cross flow across the wellbore causing a "water channeling phenomena" of up to 90% water cut across majority of the wells. As part of the productivity enhancement program for the Greater Heglig fields, a total of 23 sidetrack candidates have now been identified to capture the remaining developed reserves of ca. 30.0 MMstb, which will otherwise remain unproducible from the existing wellbore's. In addition to this, fit for purpose sidetrack well designs and construction together with good cementing practices will be required to ensure well integrity to improve reservoir management of the Greater Heglig fields.
Evaluation of Drag Reducing Agent (DRA) for Seawater Injection System: Lab and Field Cases
Authors: Al-Anazi H. A. , Al-Faifi M. G. , Tulbah F. , Gillespie J. 
Published: December 2007

Abstract
Thorough experimental studies were conducted to assess the effectiveness of a drag reducing agent (DRA) to increase the flow capacity of transfer line that supplies treated seawater to power water injectors in carbonate reservoirs and ensure it has no adverse impact on water wells injectivity. These studies included: compatibility tests, corrosion rate measurements, flow through tube tests, and coreflood experiments. Experimental results showed that the examined DRA is compatible with the currently used biocides in seawater. Corrosion tests implied that the DRA decreased the corrosivity of seawater by 50%. Flow through tube tests confirmed that the DRA reduced frictional (drag) pressure drop in the tube and increase the flow capacity. The DRA was found to be sensitive to shear where its effectiveness decreased with high shear due to polymer chains degradation. Permeability reduction was observed at higher DRA concentrations. However, degraded DRA gave less damage compared to a fresh batch. The extent of permeability damage increased in low permeability (tight) cores. The DRA caused an external damage on the face of the core, where it was removed by reversing flow direction. The examined treatments (polymer oxidizers) degraded the DRA and restored core permeability. This paper summarizes three successful field cases of this DRA in seawater injection systems. Injection rates of six wells increased up to 34% after the DRA injection in the Brent Alpha offshore field. Injection of a DRA, up to 80 ppm, increased the total volume of seawater injected by 65% in the Gyda oil field, Norway. The use of a DRA in the seawater system of the Galley offshore field resulted in re-pressurizing the reservoir and maintained oil production. Based on the obtained promised results and successful field cases, field application guidelines for using DRA seawater system were summarized.
History and Actuality of Separate Layer Oil Production Technologies in Daqing Oilfield
Authors: Xiaohan Pei , Zhipeng Yang , Li Ban , Yaning Liang 
Published: December 2007

Abstract
Separate layer oil production technologies in Daqing Oilfield were developed and improved continually with the course of the oilfield development. The technologies in the medium-low water-cut flowing period were mainly composed of the oil well packers, the Model 625 oil well regulators and the multipurpose eccentric regulating & plugging control system. In the early high water-cut artificial lifting period, 4 types of mechanical water shutoff technologies including integrated, equilibrium, slip and drillable ones were developed and applied. Furthermore, the double fluid chemical water shutoff technology was successfully studied. In the late high water-cut artificial lifting period, the water detection technology by temperature log and the profile testing technology provide accurate guides in determining the high water-cut layers. Adjustable intervals mechanical water shutoff technology and the single fluid chemical water shutoff technology could meet the requirements of subdividing oil production and water shutoff for artificial lifting wells.
Smart Snake Wells in Champion West—Expected and Unexpected Benefits From Smart Completions
Authors: Obendrauf W. , Schrader K. , Al-Farsi N. , White A. 
Published: December 2007

Abstract
Snake wells are laterally weaving ("snaking") extended reach horizontal wells that drain a number of vertically stacked, structurally dipping reservoirs. This creates multiple drainage points in each sand and effectively achieves a similar drainage pattern to a multilateral well at a fraction of the cost and technical complexity. The wells are completed with multiple hydraulically controlled interval control valves (ICV) and external casing packers or swellable packers. In addition, the completion includes permanent downhole gauges (PDHG) and distributed temperature sensing (DTS). Seven of these smart snake wells have been successfully drilled in Champion West as of April 2006 and three more are planned during the remainder of 2006.
The well design not only facilitates initial clean-up, but is used for reservoir management purposes and to manage gas and water breakthrough. Throughout the well life, variable ICVs are used to achieve equal drawdown along the well bore, leading to a significant increase in reserves by delaying gas breakthrough.
In addition, some unexpected benefits materialized from the use of smart completions: In one case, the smart completion enabled the clean-up of the initially uncompleted toe, significantly increasing total recovery from the well. In another case, the smart completion mitigated the risk from a potentially bad cement job, saving a cement repair job or, more likely, a sidetrack. In another well the flexibility of the design enabled the effective shutoff of water bearing zones that were drilled because of slight departures from the planned well trajectory. Through modification of the planned segmentation an expensive re-drill was avoided.
The smart snake wells have thus been a key enabler for the economic development of the Champion West field and we expect they will continue to add further value over the lifetime of the wells.
Case Study of Fracturing Technology to Thin Barrier in Daqing Oilfield
Authors: Jianwen Yan , Huilan Dang , Jun Lu , Lili Wang , Wei Yang , Ying Yu 
Published: December 2007

Abstract
This paper analyzes the difficulties met in reservoir fracturing in the tertiary infill campaign to recover oil from those thin, low porosity and low permeability sands in Daqing Oilfield. Vertically, these sands are characterized by thin barrier, long stridden interval between two adjacent target intervals. Due to the limitations of the barrier thickness must be longer than 2.0m and the stridden span must be shorter than 40.0m, the existing fracturing technique-separate layer fracturing cannot be adopted in these tertiary infill wells. If these thin, low porosity and low permeability sands could not be fractured, these tertiary infill wells would not produce oil economically. Based on the barrier channeling mechanism-studying results, the minimum limit of the barrier thickness is determined theoretically, 4 types of balance fracturing string have been developed, and 20 tertiary infill wells have been fractured successfully. Thus, an effective stimulation measure-balance fracturing has been developed to produce oil from those poor and thin sands in these tertiary infill wells.
The Profile Modification Evaluation by Electrometric Potential Method
Authors: Feng Guo , Li Zeng , Xuedong Zhang , Wei Chang , Honglin Yan , Jinxiu Hong , Na Li 
Published: December 2007

Abstract
After many years' waterflood, most of the blocks in Daqing Oilfield are faced with the situation of high water cut, high liquid production. More serious problems and difficulties appeared in oilfield development.
Therefore, in order to know the situation of producing wells together with the waterflood distribution and efficiency of water injection wells, it is necessary to adopt an advanced testing method to monitor the flooding direction of injected water, thereby evaluate the effectiveness of profile control on injection well group, and provide reliable information for water flooding in the future.
The Electrometric potential method is such a new technology developed to solve the above problems, available for monitoring the flooding direction of injected water. Its principle is based on that of the conduction-type Electrometric exploration techniques. With it the flooding direction of injected water and other reservoir parameters can be deducted according to the surface potential changes produced by the high ionizing energy of the injected fluid in the desired formation. It can be applied for the following purpose: Determine the flooding direction of injected water;Verify the fault and its closed property.Evaluate the effectiveness of well stimulation measures, like deep profile control etc.