bluuebunny/crossref_metadata_2025_split huggingface dataset:
Brazil Parque das Conchas Project Sets Subsea Separation, Pumping Milestone
Authors: Parshall Joel 
Published: February 2015

As first oil flowed on July 12 at the Shell-operated deepwater Parque das Conchas development offshore Brazil, it marked a major advance in the production of Brazil's abundant heavy-oil reserves and became the world's first full-field development based on subsea oil and gas separation and subsea pumping.
Situated 75 miles southeast of Vitória, off Espirito Santo state, Parque das Conchas (formerly known as BC-10) lies in approximately 4,900 to 6,500 ft of water at the northern edge of the Campos Basin (Fig. 1). Parque das Conchas in its first phase will produce from three fields, with oil ranging in gravity from 17 to 42°API. The fields will produce through subsea trees and flowlines tied into the centrally located floating production, storage, and offloading vessel (FPSO) Espirito Santo(Fig. 2). Turret-moored in 5,840 ft of water, the double-sided FPSO is equipped to process peak daily project production of 100,000 BOE, with 1.4 million bbl of oil-storage capacity. Parque das Conchas is a joint venture of Shell (50%), Petrobras (35%), and ONGC (15%).
The development grew out of a substantial exploration and appraisal program, in which Shell drilled 13 wells and made six discoveries. The project was declared commercial in 2005, and major contracts were awarded in November 2006. For Shell, Parque das Conchas is the first Brazilian project the company has taken all the way from exploration to production, as opposed to inheriting a project from another operator or initiating a project that it had to turn over to someone else to operate.

Challenges to Project's Economics
"There were a number of challenges we faced to make the project economic," said Kent Stingl, Parque das Conchas project manager for Shell. "We had heavy oil in relatively low-pressure reservoirs in an ultradeepwater environment. Hence, we had to determine how to pump from this depth and process on the production facility. But there was more to it than that. There are four dispersed reservoirs, small to medium in size, with widely divergent oil gravities and different gas/oil ratios (GORs). We needed to find an economic way of commingling and bringing production from the various reservoirs back to a central facility, with artificial lift (AL) required and subsea gas/oil separation for some reservoirs."
A further challenge was that the reservoirs, though in deep water, are only approximately 3,300 ft beneath the mudline. "Starting from vertical at the seafloor, we had to kick the wells out at a tremendously high angle to drill the horizontal wellbores required to drain these reservoirs," Stingl said. "We operated from only a few drilling centers to minimize the need to move the rig. So these horizontals extended more than 3,000 ft, and all were completed with gravel packs."
Effective Perforating and Gravel Placement: Key to Sand-Free Production
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12581, "Effective Perforating and Gravel Placement: Key to Low-Skin, Sand-Free Production in Gravel Packs," by Samyak Jain, SPE, Raymond Tibbles, SPE, and Jock Munro, Schlumberger, and Rajeswary Suppiah and Norhisham Safin, SPE, Petronas Carigali, originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.
Cased-hole gravel packing is used to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depends on the ability to pack perforation tunnels effectively. The full-length paper presents a systematic approach for perforation-damage removal, effective gravel placement, and packing of the perforation tunnels. Guidelines to surging the formation and executing the perforation-packing job are presented.

Introduction
Every year the petroleum industry spends USD millions cleaning sand out of wells and repairing problems related to sand production, and it loses additional dollars by restricted production rates. Sand production is a common occurrence in highly unconsolidated formations.
In cased-hole applications, perforations act as a conduit for fluid flow between the formation and the wellbore. Production rates can be reduced severely if the packed perforations are damaged. The ability of the well to deliver its potential productivity depends on the inflow area these perforations provide for fluid flow. Perforations may be dam-aged for a number of reasons including perforation debris, a compacted or crushed zone consisting of pulverized sand grains, perforations filled with reservoir sand, and other drilling- and completion-related activities.

Background
Perforation Surging. Perforating is the critical process connecting the reservoir with the wellbore. The selection of the gun system is driven by many factors including wellbore dimensions and formation and reservoir properties. One of the most critical parameters for perforation strategy is the rock strength, measured as unconfined compressive strength. It is recognized throughout the industry that for sand-control completions, both high shot density and big-hole charges are the optimum gun/charge configuration.
Increased area open to flow maximizes the productivity of the well while it reduces the fluid velocity per perforation, reducing the risk of sand production through the gravel pack and sand screens. High-velocity flow through isolated perforations can create "hot spots" that, with time, can erode through the screens, resulting in massive sand production and sometimes the loss of the zone or the well.
Where Is the Gap? Is It in More Reservoir Engineers or in Leveraging New Skills and Workflows That Enhance Individual Productivity?
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 118727, "Where Is the Gap? Is It in More Reservoir Engineers or in Leveraging New Skills and Workflows That Enhance Individual Productivity?" by C. Amudo, SPE, Chevron Australia, and T. Graf, SPE, Schlumberger, prepared for the 2009 SPE Middle East Oil & Gas Show and Conference, Kingdom of Bahrain, 15–18 March. The paper has not been peer reviewed.
Primary functions of reservoir engineers include estimating hydrocarbons in place, evaluating the recovery factor, and scheduling of the recovery. These roles are central in meeting the complex challenges of the development life cycle of hydrocarbon resources. These challenges have increased because mature assets require more attention to maximize recovery. The traditional deterministic approach of working is people-intensive and is no longer adequate. Statistical techniques can help in many core reservoir-engineering roles such as surveillance, history matching, and reservoir management.

Introduction
Our industry needs more people to meet the growing energy demands. The skills gap appears more pronounced in reservoir engineering because the complex issues may not migrate to automation with current traditional workflows. Reservoir-engineering practice relies, in large part, on limited, unstructured, and, often, uncertain data. With these limitations, statistical methods could be a vital part of a reservoir engineer's toolkit. Unfortunately, this has not been the case, and statistics has failed to make its way into mainstream reservoir-engineering practice. Statistics offers a disciplined approach to collecting, organizing, analyzing, and interpreting data. Statistics also facilitates the making of inferences, predictions, and decisions about the characteristics of a data population on the basis of information obtained from a subset of the population. Reservoir engineers can improve productivity and bridge the skills gap in the industry by harnessing statistical concepts and stochastic workflows that depend on these concepts.

Data Handling
Reservoir engineering centers on pattern recognition. Pattern recognition underpins well-test analysis, estimates of ultimate recovery for different development decisions, and diagnosis of reservoir and drainage-point performance. It also forms the basis for seeking analogs to verify or corroborate technical evaluations independently. To identify a pattern, one must overcome many data-related problems. These problems vary from scarcity of data in many exploration assignments to data overload in intelligent fields. This also includes how the adopted workflow handles uncertainties associated with the data.
Wellbore-Stability Performance of Water-Based-Mud Additives
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116139, "Wellbore Stability Performance of Water Base Mud Additives," by R.T. Ewy, SPE, and E.K. Morton, SPE, Chevron Energy Technology Company, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21–24 September. The paper has not been peer reviewed.
A critical property for many water-based muds (WBMs) is the ability to prevent a near-wellbore pore-pressure increase in shales. By slowing or preventing this pressure increase, an overbalance pressure is maintained that promotes wellbore stability. Using a device that simulates downhole rock stress and overbalance fluid-pressure conditions and preserved shale samples, four different muds containing different additives were tested. Direct measurements of shale pore pressure vs. time were obtained, representing the pore pressure inside the near-wellbore region.

Introduction
One of the main shale-instability mechanisms that occurs with water-based drilling fluids is the wellbore pressure penetrating into the shale pore space. This increases the near-wellbore pore pressure and reduces the overbalance. This reduction of overbalance, which acts like a support pressure for the hole, can result in shale failure and wellbore instability. This pressure penetration cannot be prevented with standard filtration additives because shale pores are extremely small, approximately 0.01 µm, and shale permeability is extremely low, typically approximately 0.01 microdarcy or less.

Experimental
Each sample was cut from preserved downhole shale core and had never been contacted by water or brine. By avoiding "premature" contact with aqueous fluids, a meaningful swelling response on the shale as caused by the drilling fluid can be measured.
Each mud test was performed on a new, preserved shale sample. The shale used for this study contains approximately 70% clay, approximately one-third to one-half of which is kaolinite, with the remainder being mostly mixed-layer illite/smectite. All samples were equilibrated to 96% activity in a vacuum desiccator before testing. This downhole shale core was cut with an oil-based mud and was kept fully preserved. The samples were cut and end-ground using decane, and they were not contacted by any aqueous fluid.
Fig. 1 in the full-length paper illustrates the inner part of the shale/fluid-interaction test apparatus. The samples were right-circular cylinders with a 0.75-in. diameter and 0.5-in. length. The sample was surrounded by an impermeable jacket, which also extends to the top and bottom end caps. This allows a confining pressure to be applied to the sample using hydraulic oil (the entire illustrated section in Fig. 1 sits inside a pressure vessel). The confining pressure represents the in-situ stress acting on the shale near the wellbore.
Single-Trip Multizone Gravel Packing
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12388, "Single Trip Multi-Zone Gravel Packing - Case Study at Handil, Bekapai and Sisi-Nubi Fields," by Mark Banman, Eric Delattre, Mohammad Sofyan, and Siswara Suryadana, Total E&P Indonesia. It was originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3–5 December. The paper has not been peer reviewed.
Stacked gravel packs involve limited technical risk, but require considerable rig time when completing deep multizone, sand-control wells. Four field developments are challenging the conventional approach to completing long sand-control zones by using newer technologies. Nineteen wells have been completed with single-trip multizone (STMZ) technology comprising 77 frac packs/gravel packs.

Introduction
For many years, simple stacked gravel packs have been used in Indonesia as the primary cased-hole sand-control method. This kind of completion involves limited technical risk, but requires considerable rig time and cost when completing multizone wells with sand-control completions. Because of escalating prices, operators completing wells with multizone gravel packs are striving to cost-effectively produce as many unconsolidated reservoirs within a single wellbore as possible.
The development of the Handil, Bekapai, Sisi, and Nubi fields illustrates the challenge of maximizing the recoverable reserves from such wells while minimizing the incremental cost of completing additional zones. These four fields are part of the giant Mahakham delta complex on the east side of Borneo Island (East Kalimantan, Indonesia). Two of these fields, Handil and Bekapai, are redevelopment projects, while Sisi and Nubi fields are new developments. All the fields are in relatively shallow waters.
In each of the fields, production comes from two major sand/shale sequences. There is a series of deeper gas sands that produce without sand control and a series of shallower, oil-/gas-bearing sands that require sand control for efficient production. The shallow hydrocarbon reserves are distributed over a large vertical interval. This leads to wells with long multizone gravel-pack completions.
Conventional gravel-pack techniques for multiple zones consist of a series of individual gravel packs, each one placed on top of the one below ("stack pack"). This generally uses at least two service-string trips per zone, one for perforating and the other for gravel packing. Use of a packer plug to isolate lower zones when perforating adds one additional trip per zone. A typical well in the Mahakham delta has five zones and would need 14 service-string trips and consume 20 to 30 rig days to install the stack pack together with the upper completion depending on the depth, perforating time, and use of packer plugs. This represents a significant capital cost.
Overview: Field Development (September 2005)
Authors: Pascolini Osvaldo 
Published: February 2015

A couple of years ago, when I started this task of annual papers selection for this feature, the focus of my statement was about the so-called “digital company.” One year later, the concept that drove my attention was the capability of parallel and accurate planning strategy, starting from the discovery well, with the early involvement of all the concerned professionals and expertise. This year, papers, seminars, and workshops show clearly the common trend to develop technology faster and look for innovative solutions strictly fit for purpose to meet the local technical requirement as soon as possible and accelerate the first production.
Although medium- to long-range R&D and technology innovation are still considered strategic issues, much effort appears to be on achieving the immediate result: technology solutions are designed and locally deployed to minimize the time to reach the market for a specific asset. Key elements of this current tendency are as follows.
- Immediate understanding of technical gaps, technical requirements, and solutions.
- Strong competency and capability of effective and efficient technology selection and deployment (make or buy?).
- Excellent communication.
However, without the third element (excellent communication), the value created by the other two elements could be much less. As a matter of fact, a successful fast technology development and application to solve a local need (as the current trend is displaying) is not a complete success if it is not shared quickly within the company.
In this perspective, communication plays an important role from the perception of the technical gap to the field application of the solution and, finally, to the fast propagation of the experience. The wise use of today’s communication strategies (e.g., the community of practices) then is an important asset to further the success stories in a timely manner.
Field Development additional reading available from the SPE eLibrary: www.spe.org.
SPE 90434 - “Optimization of Well Placement and Improved Well Planning Within a Collaborative 3D Environment Employing Real-Time Data: A Case Study From the Visund Field, Norway,” by Girling, S. B., SPE, Landmark, et al.
SPE 92895 - “Integrated Approach for Improving Development of a Mature Field,” by Xiaoguang, L., SPE, PetroChina Intl., et al.
SPE 94206 - “Shifting the Gaussian Curve to the Right—A Fully Stochastic Approach to Marginal Offshore Field Development,” by Graf, T., SPE, Schlumberger, et al.
SPE 97378 - “Technological Challenges for the Development of Ultradeepwater Fields,” by Saliés, J.B., SPE, Petrobras
Atlantis, the Quest for Stray Shallow-Water-Flow Sands
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17658, "Atlantis, the Quest for its Stray Shallow-Water-Flow Sands," by H. Mannaerts, J. Oldroyd, M. Williams, R. Fisher, E. Radjef, R. Day, J. Faulkerson, A. Pere, R. Sanders, and J. Thomson, BP plc, and K. Mix, BHP Billiton Petroleum , prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.
The presence of shallow overpressured sand bodies in the Atlantis field led to the abandonment of one of the appraisal wells and created challenges to predicting, monitoring, and controlling shallow water flow (SWF). Drilling the shallow sections of all wells in one batch enabled optimization of offshore SWF monitoring and reporting. The SWF severity-classification scheme was used successfully during the program, and it has been adopted by the U.S. Minerals Management Service (MMS) as a guideline for offshore SWF monitoring at the wellhead by a remotely operated vehicle (ROV).
Introduction
The Atlantis field, discovered in 1998, is in U.S. Gulf of Mexico (GOM) Green Canyon Block 743, approximately 150 miles south of New Orleans. Atlantis is in water depths varying from 4,500 ft to greater than 6,800 ft. Hydrocarbons from the field will be produced from a drill center at the base of the Sigsbee escarpment in Green Canyon Block 743. The water depth at the drill center is approximately 6,800 ft. The tophole sections of 15 of the 16 production wells were batch-set (drilled) over a period of 3 months during the first half of 2004. A previously existing well constitutes the 16th production well.
Appraisal Drilling
Extensive shallow-geohazard assessment at the drill center confirmed the presence of mass-transport complexes (MTCs) at various depths in the tophole section and the absence of significant shallow gas hazards. Exploration-well drilling in the Atlantis area did not encounter SWF, suggesting that the area had an overall low potential for encountering SWF despite the presence of sandy turbidites and MTCs.
The shallow-geohazard assessment for appraisal Well GC 743-4, drilled 2 years before the batch-set, was favorable. However, while the 20-in.-casing interval was being drilled, an unexpected 100-ft-thick sand was encountered within an MTC between 1,365 and 1,665 ft below mudline (Unit F). The sand flowed undetected, creating a ledge in the wellbore. Drilling continued to the proposed casing depth of 3,615 ft below mudline. As a result of borehole instability associated with the SWF sand, the 20-in. casing encountered a ledge while running to bottom, buckled, and failed. Consequently, the well was abandoned.
The appraisal well was respudded 200 ft southwest of the original location. Over-burden conditions for this well were expected to be similar, if not identical, to those of the abandoned well. However, the SWF sand associated with the MTC in Unit F, which caused the previous appraisal well to fail, was absent.
Integration Tools To Streamline Reservoir-Management and Field-Development Workflows
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93697, "Integration Tools To Streamline Reservoir-Management and Field-Development Workflows for Mature Fields in South Oman," by M.A. Naguib, SPE, E. Shahin, J. Saeby, and J. Moore, Petroleum Development Oman, prepared for the 2005 SPE Middle East Oil and Gas Show and Conference, Bahrain, 12-15 March.
Enhancements in software, hardware, expertise, and data collection and interpretation continue to improve the industry’s ability to build detailed 3D geologic and dynamic-flow models of the subsurface and to make rational reservoir-development decisions. There continues, however, to be much skepticism about the ability of the same process to contribute to day-to-day reservoir management and optimization of mature assets. A truly integrated approach can shorten the planning and study timeframe and reduce uncertainty for reservoir management in such mature assets. A system was developed that links field and corporate data to ensure that models are up to date to optimize the asset performance.

Introduction
The last decades have witnessed increasing emphasis on maximizing returns from existing assets through optimization of existing wells and surface facilities. Also, there is an increased demand for performance monitoring of each asset. Recent advances include the proliferation of real-time data from sources such as “smart wells” and the generation of multiple 3D subsurface-model realizations. These improvements in production-data acquisition and data-management technology are not always translated into real and quantifiable productivity gains, often because of a lack of suitable visualization and interpretation tools or insufficient manpower to handle the enormous volume of data, especially in brownfields. To achieve real performance gains from step changes in data acquisition and data management requires tools and people skills to integrate data across multiple disciplines.
In the southern part of Oman, an online system was developed that links (real-time and near-real-time) downhole, surface, and corporate data to ensure that reservoir, well, and facilities models are constantly monitored and updated to reflect actual operating conditions. With this “real-time” monitoring of the production system, a wide range of analysis is carried out to manage the asset performance (e.g., production optimization, facilities design, production forecasting and allocation, and loss management).
The system integrates existing software applications and streamlines the number of complex engineering tasks. The system has been applied in operational environments, and the results of some of these applications are detailed in the full-length paper.