bluuebunny/crossref_metadata_2025_split huggingface dataset:
Plugging of Fractures in Chalk Reservoirs by Enzymatic Induced Calcium Carbonate Precipitation
Authors: Larsen Jan , Poulsen Mikael , Lundgaard Thomas , Agerbæk Mikkel 
Published: December 2007

Abstract
Natural or induced fractures in a chalk reservoir can significantly reduce the recovery from a field. Therefore, plugging of fractures with a wide range of materials has been investigated over the years. Calcium carbonate, being the main constituent of the reservoir itself, is an obvious candidate. In order to apply calcium carbonate as a plugging fluid, a mechanism for delaying the precipitation has previously been suggested in the literature. This mechanism involves enzymatically induced plugging based on the mechanism of the enzyme urease converting urea into ammonia and carbonate. When carbonate is formed, it will precipitate with calcium in solution forming calcium carbonate. However, the amount of produced calcium carbonate was relatively low and the costs of the used stabilizer and high purity enzyme source was prohibitively high for bulk use. Furthermore, the calcium carbonate was produced as a slurry of small particles, which is deemed less efficient for fracture plugging compared to larger crystals or aggregates.
In this paper work on design of an improved plugging fluid based on enzymatic calcium carbonate precipitation and optimization towards a field applicable solution is presented. The relatively expensive stabilizer and enzyme source is replaced with a low cost ingredient, which also improves the rate of precipitation. By optimizing the concentrations of the reactants, we have improved the yield of calcium carbonate from the initial 20 g/L to more than 200 g/L. Furthermore, we have been able to control the crystallization and obtain much larger calcium carbonate crystals. Laboratory plugging experiments have shown that larger crystal sizes significantly improves the durability of the formed plugs.
Practical Uses of Swellable Packer Technology To Reduce Water Cut: Case Studies From the Middle East and Other Areas
Authors: Keshka Ashraf , Elbarbay Abdalla , Menasria Cherif , Smith Pete 
Published: December 2007

Abstract
Horizontal wells have become very common in the Middle East because of their capability to increase reservoir contact, particularly in carbonate reservoirs. These types of formations often are naturally fractured, and because of channeling from underlying aquifers, allow the ingress of water into the production process systems. When water breaks through to the well completion, it tends to increase and becomes preferentially produced, thereby reducing the volume of produced hydrocarbons. This phenomenon adds cost to the well operation because of the requirement to lift, separate, treat and dispose of the water. Preventing and managing water-cut through cementing, chemical application or the use of mechanical openhole barriers such as inflatable packers is costly, and often, the method chosen is not effective.
This paper will discuss the use of swellable packers to provide a long-term, completely effective, water shutoff tool. These packers use expanding rubber around the packer that expands to seal the annulus. When expanded, a permanent seal is created, regardless of whether the packer has been run as a straddle or as a plug. The packers can be used in open and cased-hole applications in all the most common oil-and gas-well environments.
This paper discusses the development and design of the packer and presents case histories from the Middle East and other parts of the world that illustrate the advantages that swellable packer technology can provide to operators in reservoirs in which water break-through has been predicted or experienced.
In these case histories, it will be shown that the packers significantly reduced water cut, which in turn, reduced water disposal costs and intervention needs while increasing production rates and extending field life.
Simulation Study of Waterflooding Performance Using Horizontal Wells in Heterogeneous Reservoirs, HMD Field Algeria
Authors: Hamadouche A. , Tiab D. 
Published: December 2007

Abstract
Due to the improvement in horizontal well construction technology, there is a tendency to extend the use of horizontal wells for improving the ultimate recovery of different recovery process, including waterflooding.
In this study, emphasize was given to several critical parameters affecting performance of horizontal injection wells in the highly heterogeneous Zone-17 of Hassi Messaoud (HMD) field in Algeria. These parameters are: position of the horizontal wellbore, perforated interval length and position, vertical to horizontal permeability ratio, and the optimum injection rate. The effectiveness of waterflooding using horizontal wells in this zone was examined in terms of sweep efficiency and ultimate recovery.
Horizontal injection wells have significantly increased injection capacity resulting in the ability to withdraw hydrocarbons from the reservoir at a higher rate. In Zone-17 HMD field, the injection/production rate can be increased by as much as four times without exceeding the fracture-parting pressure of the reservoir. Length and permeability of the perforated intervals, in heterogeneous reservoirs, have an important impact on the well injectivity and productivity. A relationship between these latter parameters has been developed.
The Value of Surveillance and Advanced Logging Applications for Brownfield Optimization
Authors: Akiode Bababola , Bhushan Vikas , Lee Robert , Mukerji Parijat , Zaouali Zouhir 
Published: December 2007

Abstract
There has been a tremendous growth in the number of high-angle and horizontal wells in the past decade. Coupled with the increase in water cut from various brownfield environments, these high angle wells present us with complex reservoir and production management challenges. Fit for purpose production logging technology is helping to provide a better understanding of fluid movement, enabling higher confidence decision making leading to successful interventions.
Production logging in high angle and horizontal wells that produce mixtures of fluid phases is challenging because of the associated complex flow regimes that radically change the physics and technology of measurement. Depending on the borehole deviation, the velocity and fluid holdup of different phases can change dramatically for a given flow rate.
We present examples that encompass various reservoir management objectives, well optimization and flow profiling. Surveillance logs were acquired in these wells to obtain key inputs for production optimisation, identifying bypassed oil and evaluating potential for additional perforations. Where necessary, production logs were integrated with pulsed neutron capture and spectroscopy measurements to enhance our understanding. In one of the examples, a compact integrated production logging tool comprising an array of spinners and holdup probes was conveyed with tractor in a horizontal well. Besides conveyance in this horizontal well, the challenge involved detecting minor oil entries in a very high water cut scenario. Two examples relate to the effective use of pulsed neutron spectroscopy measurements reservoirs. Finally one of the examples involves oxygen activation for positive identification of water movement behind pipe. Creating value through surveillance is the common thread that binds these well intervention examples together.
Development of the Gryphon Field Injection Wing—Technical Challenges and Risks
Authors: Hart N. , Ageneau G. , Mattson P. , Fisher A. 
Published: December 2007

Abstract
The Gryphon Field (UK Central North Sea) development commenced in 1993 with the successful exploitation of massive sand rich turbidite lobes of the Balder formation by horizontal wells. A component of small scale sand injection had been identified during appraisal and subsequent development but it wasn't until the acquisition of long offset simultaneous inversion seismic data in 2002 that the scale of the injection wing along the eastern edge of the field was appreciated. A full evaluation of the subsurface uncertainties led to the injection wing being matured as a development target although one which presented new challenges.
The main challenge proved to be locating and then geosteering through a three dimensionally constrained target with high lateral positional uncertainty and potential for wellbore instability. A multi-disciplinary team met this challenge with a combination of new technologies (e.g. prototype deep reading and azimuthal resistivity LWD tools) and the rigourous implementation of wellbore stability recommendations offshore.
Further technologies and strategies to mitigate these risks were introduced in the course of the drilling campaign (e.g. directional survey uncertainty reduction by In-Field Referencing and Dual Inclination techniques, landout strategies to address lateral positioning uncertainty, optimisation of well planning involving the multi-disciplinary team in a 3D environment and the use of low-rheology muds).
Production in some of the injection wing wells has substantially exceeded prediction whereas others have been more challenging to produce due to a faster than anticipated water-cut development. When averaged over all the wells, production targets have been exceeded.
The injection wing play has helped rejuvenate the field with seven wells drilled in the structure between 2004 and 2006 which, as of May 2007, have produced approximately 11 million barrels of oil and are contributing 80% of daily production.
Optimization of Tracer Test Design—Practical Applications
Authors: Meza Edgar , García Francisco , Muñoz Nancy , Reyes Carlos , Amador Arturo 
Published: December 2007

Abstract
A proposal to carry out a well to well chemical tracer test in the pilot area of a field with possibilities to implant an enhanced oil recovery (miscible CO2 injection) with two primary objectives:
Detect injecting wells that cause salted water leak at 200 meters deep in well C1001. Monitoring the injected water front behavior in each injecting well inside pilot area to define if there is vertical communication between two reservoirs.
Additional information could be possible to obtain with this tracer test as to identify the source of produced water in each producing well associated to each injecting well tagged, moreover, to measure irruption time, to identify channels or barriers that affect the fluid movement, to fix the main direction of front movement, to evaluate the front distribution inside each injection pattern in tested area and give support to field characterization in the pilot area.
To achieve these objectives, it was necessary evaluate the tracers program proposed that start with selection of injection scheme with six injecting wells tagged (one in reservoir A, four in reservoir B and one in both reservoirs) with six different chemical tracers.
We show the results of revision and analysis of each test include in tracers program and the investigation ratio adjustment used to monitoring protocol design, in which there were added several producing wells to be sampling and analyzing located inside the investigation ratio of each injecting well tagged with chemical tracer.
HP/HT Gas-Condensate Well Testing for Shell's Onyx SW Prospect
Authors: Fosså Arild , MacKenzie Derek , Steinveg Odd , Henderson Eric , Bosch Bart van den 
Published: December 2007

Abstract
This paper covers the HPHT Gas-Condensate Exploration Well, 6406/9-1 on the Onyx SW prospect of the Norway Sea in the late spring of 2005 (Figure 1 and 2). The well test design and execution is presented in the paper, including; up front planning, job design, technology selection and review of the test results vs. the objectives for the well test. The paper also addresses how health, safety and environmental considerations were handled.
Traditional well testing methods and equipment have evolved over the years, adapting to changing requirements. This has resulted in requirements for more complex data gathering over a shorter time with much stricter environmental and safety constraints. Coupled with increased needs for more accurate reservoir data for prospect evaluation, this has put a higher emphasis on upfront planning and improved technical performance together with extensive use of advanced fluid data gathering methodologies.
This paper demonstrates how the above was addressed for the Onyx SW and how the results compared with the set goals. The application of the latest technologies in Gas-Condensate well testing was used on this job. Experiences from this were later used as the basis for other gas-condensate prospects, including those in the Russian sector of the Barents Sea.
This paper focuses in particular on Fluid Sampling, Surface Well Testing and Subsea equipment. As several service companies were involved on this particular job, we have only included some general and limited content for the other services involved.
Use of Streamline Simulation for Waterflood Management in Naturally Fractured Reservoirs
Authors: Iino A. , Arihara N. 
Published: December 2007

Abstract
Waterflood management for naturally fractured reservoirs is a difficult task due to complex fluid behaviors between fracture and matrix. The streamline model is particularly useful for assessing the individual contribution of injectors to each producer accounting for inter-porosity transfer.
A simulation model for naturally fractured reservoirs was developed aiming at improved waterflood management with the use of the concept of streamline-derived injection efficiency (IE). Waterflooding in the dual-porosity dualpermeability system is first modeled by the streamline approach employing the operator splitting technique to account for gravity and transfer between fracture and matrix. IEs for individual injector-producer pairs are determined from saturation profiles on streamlines in both continua after evaluating transfer effects.
The model is capable of performing the reallocation of injection water to improve oil recovery from fracture and matrix. The model can also be applied readily to field-scale simulation because of rapid calculations with the streamline method.
This paper describes the methodology and implementation of IE-based injection-rate control for dual-porosity dualpermeability reservoirs and demonstrates the applicability by simulation examples. Application of the method makes it possible to evaluate the dynamic efficiency of the injected water for individual injector-producer pairs. Based on the computed IEs, reallocation of the injection rate among the injectors is made so that more oil in matrix and fracture is displaced by injected water. The examples showed usefulness of the method for naturally fractured reservoirs of highly heterogeneous matrix and fracture properties.
Waterflood Performance in a Depleted Fractured Chalk Reservoir
Authors: Griffin Tim , Best Kevin , Thingvoll Torgrim , Stockden Ian , Tjetland Gunnar 
Published: December 2007

Abstract
Valhall is a fractured chalk reservoir in the Norwegian sector of the North Sea which has been producing under compaction and solution gas drive since 1982. A water injection pilot led to sanctioning of the Valhall Waterflood Project which began injection in the crest of the field early in 2006. The predictions of Valhall waterflood performance covered a wide range of parameters that included fault and fracture pattern, water chemistry, compaction due to depletion and water weakening, 3 phase relative permeabilities, scaling and souring that all will impact sweep, recovery and well integrity.
To gather the key data required to make decisions in waterflood planning in the correct time frame, a comprehensive surveillance plan was drawn up. This included open and cased hole logging data, a dedicated monitoring well, time lapsed seismic and injection / production well performance data. This data is also used to manage short term waterflood issues associated with potential water breakthrough, monitoring pressures and managing the water chemistry.
Early data has revealed variability in the waterflood response in the crest. Two types of responses have been observed, a fractured zone and a more matrix dominated zone. Understanding these variations is key for placement of future injectors and for the expansion and optimization of the Valhall Waterflood Project.
Brenda Field Development: A Best Practice in Horizontal Well Placement Leading to Optimal Reservoir Drainage
Authors: Halward Ken , Emery Joe , Christensen Rod , Bourgeois Daniel , Skinner Grant , Tribe Ian 
Published: December 2007

Abstract
In 2006, Oilexco North Sea Limited developed the Brenda field in the Central North Sea. A total of over 8000 ft of horizontal section has been drilled in three horizontal production wells, all within Palaeocene-aged Balmoral turbidite sandstones below a Sele shale cap rock. To maximize reserves recovery, the horizontal drainholes not only had to cut as much of the good reservoir sand as possible, but as the Brenda field depends on water drive as its main production mechanism it was essential the wells were placed as close as possible to the top of the reservoir to ensure a greater long term field life and given the thin oil column, reduce the volume of attic oil. Generally the location of the top reservoir is visible on seismic but with significant sub-seismic variations in the top reservoir topography. Therefore to help optimal well placement, Oilexco used a new deep and directional LWD measurement in the Bottom Hole drilling Assembly in order to map the relative position of the drainhole to the overlying roof shales. As the reservoir top and internal shale layers were mapped, geosteering personnel had the ability to make changes to the directional plan to allow the well to be placed in the optimal location, at the top of the reservoir, often within 2 ft of the roof without reservoir exit.
The Brenda wells have proved to be well positioned using these new geosteering techniques. Initial flow testing of the wells was very positive with combined rates of over 26,400 BOPD with minimal reservoir drawdown. It is expected that the use of the new logging methods will result in more effective and uniform drainage of the Brenda reservoir sands, while minimizing the chance of premature water influx.
Accurate Structural Dip Interpretation in Real-Time Logging While Drilling: A Case Study From a Highly Deviated Gas Storage Well, Po Plain Basin, Northern Italy
Authors: Morris S. , Glass C. , Zurcher D. , Maletti G. , Borghi M. , Marzorati D. , Barbieri E. , Scanavino D. 
Published: December 2007

Abstract
In a recent well, drilled in the Po Plain basin of northern Italy, a high resolution logging-while-drilling (LWD) electrical image was acquired to undertake real-time structural analysis over a thinly bedded mixed sandstone sequence within a highly deviated gas storage well. An objective was to validate the accuracy of the real-time high resolution images for future geosteering applications in a complex area with many petrophysical uncertainties and operational limitations.
The operators identify that the right measurements to support high resolution structural dip evaluation in real-time will allow geosteering uncertainties to be reduced further, and that this can result in better decision-making and ultimately optimal payzone penetration.
Real-time dip analysis from the electrical image has been favourably compared with results from the memory data and other imaging devices in the same BHA (gamma ray and density) and also with wireline electrical images from the same well. This case study also presents advanced sedimentological and structural applications of LWD electrical images and highlights imaging resolution capabilities now possible while drilling.
The Injection of Multifunctional Chemicals via Gas Lift Increases Oil Production
Authors: Jackson Mike 
Published: December 2007

Abstract
Gas lift production is well known for its sensitivity to high viscosity fluids that can be produced when oil and water form emulsions downhole. Gas lifting can produce emulsions which are stabilized with naturally occurring components such as asphaltenes, paraffins, inorganic scales and sands. These factors; sensitivity to high viscosity fluids and the potential for the generation of emulsions, makes gas lifted wells ideal candidates for the injection of friction reducers. Friction reducers can also be formulated with different chemical additives to address other potential problems, such as scale, corrosion, hydrogen sulfide and hydrates. The injection of a single chemical product containing a mixture of different types of additives is known as a multifunctional product. The injection of one single multifunctional product into the gas lift gas can solve the logistical issues of multiple tanks, multiple injection pumps while solving problems downhole and in the flow line.
This paper will concentrate on the development and application of multifunctional products that contain friction reducers as the primary additive. This paper reviews the conditions that can cause downhole emulsions, the laboratory techniques used in the product selection and the laboratory procedures to investigate compatibility issues. Case histories of successful applications off-shore Brazil.
Multi Type Application of Cement-Packer: Simple and Economic Method of Accessing By-Passed Reservoir Potential
Authors: Idris Muhammad , Rylance Martin , Joenoes Krisjahbana , Firmansyah Nanang , Supriyono Anton 
Published: December 2007

Abstract
Over a significant time-period, during the development of a field; a number of factors will contribute to an increased understanding and appreciation of the identification of pay, it's distribution and potential. As a result, it is not unusual to find that a significant number of opportunities may exist within existing well-stock; but that these opportunities are ‘isolated’ by limitations of the original completion design. Accessing these reserves then simply becomes a question of completion ‘adaptability’, optimization and economics. Therefore this paper describes the application of a rig-less ‘cement-packer’ approach, in order to economically access these reserves, while retaining the necessary level of completion integrity. The paper describes the steps involved in achieving this, from concept, through planning to execution. Finally, a number of case-studies (with variants) are presented to demonstrate the increasing development and applicability of the process.
Within VICO Operations, the cement-packer process was first introduced in 1995, since then a number of variants of the approach have been developed and applied. These variants have been driven in response to individual well limitations, special requirements and also with increased technical understanding and experience. These continuous improvements have meant, that since 1995, more than 70 wells have now been remediated using this approach.
Historically, the cement-packer operational approach has been extremely efficient and has enjoyed a high mechanical success rate. In addition to this, the majority of these treatments have been performed on idle well stock; with over 50 idle-wells having been returned to production. In terms of their success, the cement-packer treatments have delivered at economic rates to VICO, where conventional work-over operations would not have been a viable option.
It is likely that an operator would consider that such by-passed opportunities would generally require a costly, lengthy and complex work-over operation; and potentially discard the option due to the economics and risks. However, this paper clearly demonstrates that the cement-packer approach is a simple, efficient and economic method of accessing such bypassed pay, while helping ensure acceptable well-bore integrity is retained.