bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Design for Advanced Well Completion
Authors: Madsen Martin 
Published: December 2009

Abstract
Advanced well completions (AWC) have shown great benefits not only with respect to production optimization, but also data collection were they provide very useful PLT type information on a zonal basis (ref. 1, 2, 3).
However, as many of the wells with advanced completions have matured and more data been acquired over longer production periods, some a better understanding of the production behaviour has been gained.
Installing an inner tubing with associated flow control valves in a horizontal liner causes restrictions to the flow, and an increased pressure drop. One the StatoilHydro operated Visund field, one has observed that at certain well conditions (related to combinations of rate, water cut (WC) and gas oil rate (GOR) this pressure drop leads to a noticeable reduced well potential, and thereby a reduced overall robustness of the well design. By increasing the production liner diameter in the reservoir section, one may be able to install advanced completion equipment with bigger dimensions. This allows the benefits of the downhole zonal control to be realised without hindering the well potential.
Data from two wells one the Visund field, has been used to demonstrate the benefits related to increasing the diameter of the production liner, and consequently the dimensions of the advanced completion components. A hydraulic well model has been constructed comprising one producer and one gas injector. When the models are matched to actual rates (and well conditions), the effect of varying the flowing diameter (= inner tubing diameter) is studied. The results show that there is an upside with regards to flexibility and well potential with such an optimized completion design. In relation to the model findings, the consequences for the drilling and completion design and processes are outlined.
Integrated Surveillance Enhancing Quality of Decisions and Reservoir Description in Harding
Authors: Zett Adrian , Webster Mike , Davies Chris , Zhang Pinggang , Mukerji Parijat 
Published: December 2009

Abstract
A key factor in managing mature fields is to identify adequate surveillance in each phase of its life. The complexity increases when the field is developed with horizontal wells. Differences in data quality and resolution should be taken into consideration when planning such surveillance. Current uncertainties in Harding relate to unreliable well conformance data using conventional production logs and assumptions in the reservoir description which are sub seismic resolution. We describe the learning from a horizontal well in the Harding Field, where appropriate surveillance enhanced reservoir understanding and quality of decision making.
Based on the initial understanding from the reservoir model, an insert string well work option was proposed to reduce water cut. Historically in this field, conventional production logging provided unreliable well conformance data in horizontal multiphase flow. To improve the characterization at the well scale, an array production log was deployed for the first time on this field.
The flowing results revealed that the insert string solution was inappropriate and would result in lost oil production. The shut in data identified cross flow between two zones separated by a shale section. In the initial model this shale was mapped only at local level. Post surveillance it was remapped on seismic as an extensive baffle having an impact on an area with more mobile oil to recover. There is potential upside with a new infill target being identified towards the toe of this well. Most of the initial decisions about the insert string were based on seismic and modeling work. The new array production log data brought additional information into the model increasing confidence in the results. Data resolution at the well level matters and this highlights the need to take more production log measurements to calibrate the seismic response and improve the reservoir model.
‘S’ is for More than Just Safety
Authors: Kain Andrew 
Published: December 2009

Abstract
Kidnap for ransom, piracy, terrorist attack, criminality, war, expropriation and wider political risk, are all challenges the upstream sector has faced over the last 12-month period. These challenges will continue, and it is highly probable that they will actually increase. Challenges to the discipline of ‘Health, Safety and Environment’ include the very environments in which the energy sector operates, particularly as frontier locations are explored and as many existing regions of operation are affected by instability, conflict, extremism and other security and political risks.
As an industry the energy sector is highly regulated, and is policed by the discipline of HSE. Qualifications and certification for deployment to the UK's own backyard, the North Sea, are plentiful. It is thus somewhat surprising that often nothing more is required of personnel prior to their deployment to areas of operation further afield, where potential security challenges are more prevelant. Those tasked with crisis management responsibility are also often under-prepared for this role, and the unique challenges to be faced.
This paper discusses the industry's successes and failures in terms of security risk mitigation and the requirement for the "Security S" to be incorporated into the wider remit of HSE management. It highlights what can and has been done to minimise the risk to personnel operating in challenging environments.
Real-Time Decisions With Improved Confidence Using Azimuthal Deep Resistivity and At-Bit Gamma Imaging While Drilling
Authors: Harris Michael , Byrd David , Archibald Michael , Naupari Carlos , Bittar Michael , Chemali Roland 
Published: December 2009

Abstract
Recent advances in logging-while-drilling (LWD) have thrust geoscientists in the fast world of real-time decisions. The interpretation of images and logs for successful well positioning requires a higher level of urgency and criticality than with post-well formation evaluations. When advising drilling engineers about well steering, geoscientists have little room for second guessing or revisiting even very recent decisions. The method described in this paper takes advantage of newly developed LWD sensors. The new information helps increase confidence and reduces errors when making real-time steering decisions.
Geosteering experience consistently shows that the formation discovered as the well progresses is significantly different from the pre-drill models. Even in simple layered environments, it is often difficult to recognize in what layer is the well moving. Within a particular layer, there is often ambiguity regarding the relative well position. Crossing into a shale or across a subseismic fault creates an emergency for bringing the well back to the predicted course. Modern azimuthal deep resistivity provides the means to see to a greater radial investigation the formation surrounding the well, but the acquired raw data is complex and must be organized and interpreted instantly.
A recent geosteering operation was successfully completed using the azimuthal deep resistivity information and combining it with near bit gamma images for maximum reservoir contact. Resistivity readings in opposite quadrants were monitored and compared. When they were similar, the well was too far below the roof and must be steered upward; when they separated, the magnitude and direction of the separation was uniquely related to the approaching boundary and correlated with pre-well model. The diagnosis was confirmed and often anticipated by a higher level measurement: the geosignal. Because of its early detection of approaching boundaries, the geosignal facilitates proactive decisions. The well achieved full reservoir contact with no uncontrolled exit. The image from the near-bit gamma was used only when landing the well and when finally exiting the reservoir. Between these two milestones, gamma images had only a verification role, confirming throughout that the well stayed clear of shale intervals.
Managing Safety & Risk Issues in Upstream Field Development—Case Studies
Authors: Phang Christina , Yng Voon Jye , Leong Christie 
Published: December 2009

Abstract
An important element of a field development project would be ensuring that relevant safety features are incorporated within the design of the facilities such that the risk to personnel working on the facilities are deemed to be tolerable from a company or regulatory perspective. It has been observed that different oil and gas operators have varying requirements with regards to the breadth and depth of the suite of formal safety assessment studies that are conducted at the different development stages. This paper will present an overview of the practices adopted by various operators based on the experienced gained through ERM's involvement in major field development in the Asia Pacific region. Similarities and diversity of the approach taken will be explored with the aim of sharing best practices that are applied in the industry.
The paper will explore the optimum results gain by conducting the safety assessments, including the use of Quantitative Risk Assessment as a management decision tool, during the early stages of the development projects taking into account the available information available. The paper will also include a discussion on the degree of effort required in achieving a final configuration where the risks to personnel working on the facilities are demonstrated to be As Low As Reasonably Practicable (ALARP) such that the investment in reducing the risks is not grossly disproportionate to the benefits that may be achieved.
Case Study: Successful Application of a Novel Conformance Treatment in an Extended Reach Horizontal Well in the Al Shaheen Field, Offshore Qatar
Authors: Pedersen M. H. , Lechner M. , Pon Z. A. , Brink D. , Abbasy I. , Jaafar M. R. 
Published: December 2009

Abstract
The thin and laterally extensive Al Shaheen reservoirs are developed with extended reach horizontal wells and large-scale water injection, which over the last decade has proved to be a proficient and environmentally favorable recovery scheme. This paper describes how injection water short circuiting between two horizontal wells in excess of 20,000 ft was eliminated with a conformance treatment without the necessity of a costly and operationally risky well intervention. Traditionally, reservoir management in terms of injection or production profile modification has been achieved with rig-based work-over operations applying mechanical solutions such as cement or isolation straddles. Work-over operations utilizing drilling rigs are, however, expensive, pose inherent operational risks and delay the implementation of the ongoing development plans. When water injection was recently commenced in a well taking part of an existing line drive pattern, an immediate pressure and watercut response was observed in the adjacent producer. Attempts were made to mitigate the effect of the communication, but water injection eventually had to be ceased to allow sustainable flow from the production well. The very pronounced response in the producer suggested that short circuiting was occurring through a fracture providing conductivity several orders of magnitude higher than the prevailing matrix conductivity.
A comprehensive multi-disciplinary review of static and dynamic data lead to the assessment that the fracture communication could be eliminated utilizing a conformance treatment and following laboratory testing and design, a crystalline superabsorbent copolymer was pumped from a stimulation vessel as part of an intervention- and rig-less operation. After the conformance treatment, injection was resumed with no adverse effects on the performance of the adjacent producer. The treatment is estimated to have recovered lost oil reserves of some 3 MMstb and to have reduced cost with more than USD 8 million compared to a conventional rig-based work-over operation.
CO2CRC Otway Project, Australia: Parameters Influencing Dynamic Modeling of CO2 Injection into a Depleted Gas Reservoir
Authors: Bouquet S. , Gendrin A. , Labregere D. , Le Nir I. , Dance T. , Xu J. , Cinar Y. 
Published: December 2009

Abstract
The CO2CRC Otway Project, in Victoria, Australia, is one of the first projects of CO2 storage in a depleted gas reservoir. CO2 injection in the sandstone reservoir, at a depth of 2,000 mSS, started in March 2008 with the objective to inject up to 100,000 tonnes of CO2 over two years.
This study compares the level of predictability obtained with different cases depending on the initial data, using the same numerical compositional simulation package. We use recorded data (production and injection) to build a new numerical reservoir model. A dynamic model had already been built before the injection well started (Xu et al., 2006) and was validated by history matching using the gas production data reported. In this paper, we used the same updated static model (Dance et al. 2007) as used for the pre-injection model, which is based on the production data and the data obtained from the injection well (CRC-1). With this updated static model, a different dynamic model is built using injection data and through a newly developed simulator option, which better simulates the CO2-water behavior. The injection rate and pressure data from CRC-1 are now available and the actual breakthrough time – at which the CO2 plume reached the monitoring well (Naylor-1) located 300 m away from CRC-1 – can be history matched. Various relative permeability curves including new laboratory measurements performed on a core taken from the reservoir formation (Waarre C) were used. The results from the updated dynamic modeling using this measured relative permeability data are compared to results using data from literature. In general, experimental measurements for drainage and imbibition processes are not available
This study gives a better understanding of the parameters which strongly influence simulated CO2 behavior. It shows the relation between the data availability and prediction reliability.
Managed Pressure Drilling Applications Proves Successful in the Middle East and North Africa Region
Authors: Arnone M. , Vieira P. , Torres F. , Qutob H. , Babajan S. 
Published: December 2009

Abstract
There is no doubt that Managed Pressure Drilling (MPD) technology will to be applied in the near future as the conventional practice to drill what is today defined as undrillable, hazardous and expensive wells. The several analyzed cases, applications and results obtained in the Middle East and North Africa region clearly leads to this conclusion.
Managed Pressure Drilling, from the core concept point of view, is a collection of drilling optimization techniques that when correctly designed, planned and applied will improve the overall drilling performance, mitigate risks and reduce operating costs by proactively managing the hydraulic pressure profile and solving the problems associated with high Non Productive Time (NPT) commonly experienced with conventional drilling practices. This simple concept is what promotes this technology to be the new standard and conventional drilling practice in the near future.
From the technical point of view, IADC defines MPD as an adaptive drilling process used to precisely control the annular pressure profile throughout the drilled wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly, avoiding continuous influx of formation fluids to the surface. Any influx will be early detected, managed and safely contained. MPD may include semi-automatic or full automatic control of annular backpressure, fluid density, fluid rheology, annular fluid level, circulating friction, hole geometry or combination thereof. MPD represents the ability to dynamically control annular pressures, optimizing the drilling process facilitating what might otherwise be economically unattainable prospects.
This paper summarizes the process used to visualize the ideal prospects, the conceptual development including re-engineering planning and design phases, the process to implement the technology and the results obtained, lessons learned and the range of opportunities this technology has created in the Middle East and North Africa region from year 2007 to early 2009.
Improving Operations Through Increased Accuracy of Production Data
Authors: Wising U. , Kalitventzeff P.-B. , Campan J. , Vrielynck B. 
Published: December 2009

Abstract
Production Engineers have more and more information available and operating companies are trying to integrate that information and create an "integrated oil-field" with the main objectives of maximizing production and at the same time maximize recovery. One of the challenges in these types of approaches is the quality of production data. By not having accurate enough production data, the integration efforts are covered in a layer of haze, uncertainties. By combining advanced data validation and data reconciliation techniques it is possible to improve the quality of production data and quantifying all flows, temperatures, pressures and compositions throughout the production network.
This technology has been applied in the downstream area for years and are now more and more being deployed in oil and gas production. The main goal is to provide accurate flow of oil, gas and water in each production well, but it can and has been applied to water injection systems, gas fuel and flare systems, FPSO's etc.
It has been shown that it is possible to provide accurate production data in a production network. In particular, it has been shown that even on wells that do not have multi phase flow meters, it is possible to determine the flow of oil, gas and water with an uncertainty of less than 10%. In addition it provides other types of virtual meters, in general a production network with x measurement, would have another 2*x measurements validated and reconciled. Also by comparing measured data with validated and reconciled data it is possible to draw some conclusions; for example sensors and equipment that need maintenance can be identified much earlier and maintenance can move towards conditioned based, predictive maintenance.
This is a digital technology that can help operators have a better understanding of how their assets are performing and can help in increasing recovery from each well in the production network. Injection schemes can be performed more optimally and capacity from a field can be expanded in a cost effective way.
Formation Testing, Completion Integrity Evaluation and Geomechanical Applications Using a Wireline Cased-Hole Formation Tester
Authors: Ardila Mario , Achourov Vladislav , Gisolf Adriaan , Williams Stephen 
Published: December 2009

Abstract
Wireline formation testing is traditionally carried out in open-hole wells. Advances in formation tester technology have provided the industry with a new modular cased-hole formation tester (CHFT). In this new design a hole is drilled through the casing and cement, communication with the formation is then established enabling formation testing and sampling. The drilled hole is subsequently plugged.
This paper describes several case-studies from the North Sea where a full range of formation testing applications (that would traditionally be performed in open-hole) were made in casing using a cased-hole formation tester. In addition to pressure testing and sampling, three recent case studies demonstrate advanced applications.
The first example demonstrates zonal isolation behind casing and identifies communication between layers under injection. The reservoir consisted of two layers with significant permeability contrast. The CHFT was set at the bottom of the higher permeability zone and a hole was drilled thought the casing and annulus. The pressure was monitored while seawater was injected at increasing pressure steps into the lower permeabily zone. By analyzing the pressure response the degree of zonal communication and the maximum injection-rate were obtained.
In the second example, the CHFT was used to determine whether production wells could be drilled safely, and to evaluate bypassed reservoir layers. A very deep and deviated injection well completed and perforated over a long interval was tested with a CHFT deployed by tractor. Formation testing results provided a formation pressure profile in un-developed zones and showed that the injected interval was over-pressured and above the maximum safe pressure for drilling operations.
The final case study described in this paper shows an application of the CHFT for shale integrity testing. A poor cementing operation potentially left a production well without zonal isolation. The overburden shales are weak and prone to collapse. If the quality of the seal provided by the collapsed shale is tested for integrity and can be qualified as a barrier providing zonal isolation, the operator could avoid the expense of drilling a side-track. Two effective-stress testing cycles were made with the CHFT, which confirmed the integrity of the shale barrier, and quantified the minimum horizontal stress.
Deep Offshore Fracture Pressure Prediction in the Niger Delta - A New Approach
Authors: Ajienka Joseph , Egbon Franck , Onwuemena Uchechukwu 
Published: December 2009

Abstract
Drilling in deepwater is becoming more and more expensive. There is need to know before hand, for well planning purposes, the values of the fracture pressure. The Fracture pressure could be determined by predictive or verificative methods. Many correlations exists that can be used to predict the fracture pressure. However, they are mostly limited to onshore and shallow water fields. There is therefore the need to develop correlations that can reliably predict the fracture pressure for deep water fields.
This paper explores the concept of developing and possibly modifying some existing correlations to suit deep offshore needs as well as develop an Excel Spreadsheet and a V-Basic program that can be used to predict fracture pressure for deep offshore fields both in the Niger Delta region and the Gulf of Mexico. Furthermore, the predicted fracture gradient (LOT) values yielded by the various correlations were compared with actual LOT from a particular deep offshore field in the Niger Delta and the results analyzed.
The results of the analysis showed that some of the correlations studied, especially Matthew & Kelly, can be used to reliably predict the facture gradient for deep offshore fields.
Understanding Dynamic Simulation Results
Authors: Obidike Peter 
Published: December 2009

Abstract
Reservoir engineering tools applied in development planning or operations support ranges from material balance calculations to simulation studies. The results from a full 3D complex reservoir simulation study comprise a large amount of data. To better appreciate the result of the calculations, simulation packages make use of various visualization tools such as 2D plots or 3D displays. Properties such as water cut and sweep arrays can be visualized with the 2D or 3D displays respectively. These plots enable an understanding of the result of a reservoir simulation run. In some cases the results are easy to understand and appreciate, for example increasing well count you may likely recover more oil. In some other cases surprises may be resolved by investigating the underlying principles of fluid flow through the grid blocks. Because of the complexity of some reservoir models, a systematic approach may be necessary to understand what is going on in the system.
Developing these interpretation skills require hands-on assignment of reservoir simulation problems and coaching by more experienced reservoir engineers. Some cases that give insight to strategies in understanding the simulation output and making good engineering decisions are discussed in this paper.