bluuebunny/crossref_metadata_2025 huggingface dataset:
Multiple-Layer Completions for Treatment of Multilayer Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112476, "Multiple- Layer Completions for Efficient Treatment of Multilayer Reservoirs," by Gary Rytlewski, SPE, Schlumberger, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.

A new method of completing multiple-layer formations has been tested successfully. This new method places sliding-sleeve valves in the casing that are opened one at a time to fracture layers independently without perforating. Completions using these casing valves have a unique design feature that allows a theoretically unlimited number of valves to be placed in a single well without incremental reductions to the inside diameter (ID). This near fullbore feature allows normal cementing operations to be performed with a special cement wiper plug.

Introduction

The US and Canadian tight-gas market is deploying new methods to stimulate multiple-layer reservoirs efficiently. The treat-and-produce (TAP) completion system has been developed to allow efficient treatment of individual layers in cemented cased-hole completions. TAP completions use special casing valves that isolate individual layers. The TAP valves are near full bore and do not require incremental ID reductions, thus allowing normal cementing operations. The TAP valves also have unique helical ports that align to any preferential fracture plane, regardless of the orientation of the valve in the casing string. These ports ensure that a single bi-wing fracture plane is initiated from the wellbore. Fracture-initiation pressures with TAP valves are expected to be comparable to openhole fracture-initiation pressure or be lower.

The Main TAP Valve

The main TAP valve is a sliding-sleeve valve with several unique features that enable it to open selectively one valve at a time and isolate previously treated layers. There is a C-ring in the main TAP valve that, when squeezed by a piston, reduces in size. The C-ring originally has the same ID as the valve, but when reduced in size, the C-ring becomes a seat on which the next ball or dart can seal. Fig. 1 shows a cross section of the main TAP valve and the C-ring in the run-in-hole position. The piston that squeezes the C-ring (the magenta-colored component in Fig. 1) is controlled by the pressure in a control line connected to the TAP valve below it. When the lower TAP valve is opened, the port to the control line is opened to the ID fluid. The control line, which was at atmospheric pressure, now has bore pressure. The upper TAP valve receives the bore pressure through the control line and ports it to the C-ring piston. The C-ring piston has two atmospheric chambers. When the bore pressure floods one of these atmospheric chambers, the C-ring piston moves and squeezes the C-ring and is able to catch the next ball or dart pumped down. When the dart lands on the C-ring seat, it creates a seal, and pump pressure pushes the sleeve open.
Technology Focus: Wellbore Integrity, Sand Management, and Frac Pack (September 2008)
Authors: Goodman Harvey E.
Published: February 2015

Technology Focus

This year's focus is on the completion. A paper on near-wellbore modeling of sand-production behavior provides well engineers a glimpse into the world of cutting-edge rock-failure forecasting. The paper provides engineering practitioners valuable insight into the challenge of predicting produced-sand rates on a fieldwide scale.

A second paper incorporates sand failure and produced-solids-transport fore-casts with the effects on surface facilities and production by use of a probabilistic approach to manage the uncertainties. This work provides a framework that may be used to move innovative reservoir- and production-systems failure models to the fieldwide level, which is necessary for asset management. The goal is to characterize the asset-development-plan cycle from appraisal through abandonment.

A third paper presents a possible solution to the proppant-flowback problem associated with screenless frac-pack completions. The approach involves resin coating of the proppant during pumping, and a convincing argument is presented supporting induced-fracture-conductivity preservation after placement. For deepwater completions, this issue can be extraordinarily expensive and is a very real concern when evaluating risk in completion-design alternatives.

A common theme among these papers deals with the challenge of scaling up laboratory learnings to field-development practice. Today's multidiscipline-team approach to field development can provide the connection needed to foster an awareness of the effect of diverse laboratory-measurement data on asset-development viability.

Wellbore Integrity, Sand Management, and Frac-Pack additional reading available at the SPE eLibrary: www.spe.org

IPTC 11472 • "Mechanical-Earth-Model Calibration for Sanding-Potential Estimation: A Case Study From the Tombua-Landana Development in Angola's Deepwater Block 14" by Peng L. Ray, SPE, Chevron, et al.

SPE 109662 • "Enhanced Mechanical Earth Modeling and Wellbore-Stability Calculations Using Advanced Sonic Measurements—A Case Study of the HP/HT Kvitebjorn Field in the Norwegian North Sea" by Anke S. Wendt, SPE, Schlumberger, et al.
Near-Wellbore Modeling: Sand-Production Issues
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 109894, "Near-Wellbore Modeling: Sand-Production Issues," by Guillaume Servant, IFP; Philippe Marchina, SPE, Total; and Jean- Francois Nauroy, IFP, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November 2007. The paper has not been peer reviewed.

Sand production in an oil or gas well can cause operational difficulties, but it contributes to production enhancement by improving the well inflow performance. To assess the relative magnitude of those effects and to optimize the well completion and operation, a quantitative forecast of the expected amount and rate of sand production must be made. This forecast requires a correct description of all the mechanisms involved in sand production, sand transport in particular. The proposed numerical method considers that the geomechanical problem (rock failure) interplays with the transport of sand. Equilibrium equations that control rock failure (solid mechanics) and sand transport (fluid mechanics) are solved simultaneously by an iterative coupled scheme at the wellbore scale.

Introduction

Sand production causes production problems and can generate safety and environmental hazards. However, it can increase the inflow performance of the well. Therefore, the option of installing downhole sand-control equipment may not always be the best economic solution for the project.

Heavy-oil reservoirs can benefit from allowing sand to be produced with the oil. This technique, known as cold-heavy-oil production with sand (CHOPS), allows higher production rates than conventional techniques. Again, the productivity and ultimate delivery of the well will depend on the amount of sand produced. Therefore, the ability to anticipate the sand-production mechanisms in terms of sand rate and volumes, and anticipate sand-producing patterns in the reservoir, is required for optimized development of such fields.

Two mechanisms contribute to sand production: rock failure (through which freed sand grains are generated) and transport of those free grains by the effluents into the wellbore and up to surface. Most current sand-production-risk models concentrate on the rock-failure analysis and, as such, can determine only the conditions for the onset of sand production. In the proposed model, the rock-mechanical aspects are coupled to the sand-transport problem. Therefore, interaction between the solid matrix and the slurry flow can be analyzed and translated into quantitative sand production. Paralleling development of this numerical model, a series of sand-production experiments was carried out in a purpose-built laboratory apparatus with the objectives of understanding the sand-production processes in uncemented reservoirs better and providing high-quality data sets for calibrating the model.
Discussion of Climate Changes Everything: The Coming Revolution in the Energy Industry
Authors: Holliday G.H. , Davis Kerry , Thorogood John L. , Simon A.J.
Published: February 2015

Discussion

Editor's Note: JPT received several letters regarding Joseph Stanislaw's Guest Editorial in the June issue on "Climate Changes Everything: The Coming Revolution in the Energy Industry." Excerpts of some appear below.

To the Editor:

I found the June 2008 Guest Editorial authored by Joseph Stanislaw interesting, but not necessarily believable. Like so many climate change articles, the author combines the issue of climate change with energy independence. I am neither an atmospheric physicist nor a meteorologist, but I have read extensively on climate change. Stanislaw concludes that anthropogenic greenhouse gasses, e.g., CO2, cause increased global temperature. He supports that position by referring to an Intergovernmental Panel on Climate Change (IPCC) report. My reading convinces me that the IPCC conclusion is based on computer simulation using wholly inadequate programs. The research conducted by Dr. Willie Soon (Horner 2007, Fig. 3, 146), demonstrates no correlation between CO2 and temperature change. Dr. S. Fred Singer, in personal communication (2008), states that CO2 is a lagging indicator of climate change and this lag is on the order of 600 years.

Interestingly, on 23 March 2008, the Hadley Climate Research Unit in Britain, the NASA Goddard Institute for Space Studies in New York, the Christy Group at the University of Alabama, and Remote Sensing Systems Inc. in California reported that global temperatures decreased 0.7°C during 2007. These measurements could be interpreted as a sign of global cooling rather than global warming.

Stanislaw's discussion regarding the need for energy research is on target. We need energy to sustain our standard of living and help emerging countries with their energy needs. But, justifying this research on the basis of questionable climate prediction is wrong. G.H. Holliday

Reference

Horner, C.C., 2007. The Politically Incorrect Guide to Global Warming and Environmentalism, 146. Regnery Publishing Inc.
Interview with 2010 SPE President Behrooz Fattahi
Authors: Fattahi Behrooz , Donnelly John
Published: February 2015

President's interview

Behrooz Fattahi is coordinator, Heavy Oil Development, Aera Energy, a California E&P company jointly owned by affiliates of Shell and ExxonMobil. He began his industry career in 1977 and subsequently worked as a reservoir engineer, reservoir-engineering manager, and team leader for Osco/Shell International, Shell Western E&P, Shell Offshore, and Shell affiliate CalResources. Before joining the petroleum industry, Fattahi conducted research for the US National Aeronautics and Space Administration (NASA) and the US National Science Foundation and taught courses in fluid dynamics and solid mechanics at Iowa State University. He is a past member of the American Institute of Aeronautics and Astronautics and the American Association of University Professors.

Fattahi has served on the SPE Board as director of the Western North America Region, and as vice president, Finance. Additionally, he has been chairman of the SPE Continuing Education Committee, a member of the SPE President's Learning Initiatives Task Force, and executive editor of SPE Reservoir Evaluation & Engineering, and was chairman of the San Joaquin Valley Section. Fattahi holds PhD degrees in aerospace engineering and mechanical engineering from Iowa State University.

How did you get involved with SPE?

I joined the oil industry in 1977, working in Iran for Osco/Shell Company. There was an interruption in my SPE membership because of all the events in Iran at the time, but when I came back to the US in 1985 to work for Shell in New Orleans, I became a member again. At the time, I had a passion to work on behalf of SPE but I did not really know how to, and I suspect that there are a lot of people today who have that problem—they want to get involved but they do not know the avenues to take and where to start.

It was not until I began working in Bakersfield, California, in the early 1990s that I really got involved with SPE. One day I received a call from a friend at Chevron who was on the board of the SPE local section and he asked me if I could help him with the continuing education program because he was going to move the next year. And that turned out to be the opportunity that I was looking for. I got involved in that program and, after he left, I was able to become the section's Continuing Education director and significantly increase the size of the continuing education program.
Horizontal-Well Fracturing: Why Is it So Different?
Authors: Daneshy Ali
Published: February 2015

Technology Update

Advances in drilling and fracturing horizontal wells have been two of the main contributors to economic production from very-low-permeability oil and gas reservoirs. In spite of much attention to the subject, several critical questions regarding horizontal-well fracturing remain unanswered. Among these are higher fracturing pressures, large pressure fluctuations, and more frequent screenouts, which has prompted use of much finer proppant at very low concentrations. This article answers some of these questions.

Fracture Initiation From Horizontal Wells

The state of stress in a borehole gives it a natural tendency for longitudinal (axial) fracture initiation (Fig. 1a). This is a geometrical effect and independent of the in-situ stress orientations (Daneshy 1973). It can occur even when the least in-situ principal stress is parallel with borehole axis. Since the fracture is not perpendicular to the least in-situ principal stress, it takes higher pressure to extend it. As the axial fracture grows, it will eventually reorient itself to become perpendicular to the least in-situ principal stress and the fluid pressure gradually decreases with it. The location of fracture reorientation depends on location and orientation of planes of weakness in the formation. This leaves open the possibility that the fracture may reorient itself more than once, and depending on the orientation and size of the plane of weakness, may temporarily grow in directions other than perpendicular to the least in-situ principal stress.

Initiation of a transverse fracture (perpendicular to borehole axis) requires axial forces and stresses (parallel with borehole axis), which is shown in Fig. 1b. In open holes, such stresses can be induced inside open natural fractures, at the packer seats, or at the bottom of the well (if exposed to fluid), each with its own characteristics. This is shown in Fig. 2.

Natural fractures are randomly located and distributed along the well. Initiation from natural fractures results in random location, orientation, and spacing between fractures. One way for partial location control is to reduce the spacing between the packers, thus reducing the length of the pressurized interval.
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.
Shared Vision (October 2004)
Authors: Paccaloni Giovanni
Published: February 2015

President's column - No abstract available.
Techbits (October 2004)
Authors: JPT staff _
Published: February 2015

Techbits - No abstract available.
Heavy-Oil Solution-Gas Drive for Hamaca Field: Depletion Studies and Interpretations
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 86967, "A Study of Heavy-Oil Solution-Gas Drive for Hamaca Field: Depletion Studies and Interpretations," by Cengiz Satik, SPE, ChevronTexaco; Carlon Robertson, SPE, Petrolera Ameriven; Bayram Kalpakci, SPE, Technip Offshore Inc.; and Deepak Gupta, SPE, Westport Technology Center, prepared for the 2004 SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting, Bakersfield, California, 16-18 March.
Integrated Reservoir Study of the Shushufindi Field - Dynamic Modeling
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89465, "Integrated Reservoir Study of the Shushufindi Field - Dynamic Modeling," by Henry A. Ohen, SPE, Adel Erian, SPE, Liaqat Ali, SPE, and Daniel Guzman, SPE, Integrated Reservoir Solutions, Core Laboratories, and Olga Guerrero, Jose Ochoa, and Luis Valdivieso, Petroproduccion, Ecuador, prepared for the 2004 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 17-21 April.
Oriented Perforations as a Sand-Control Method
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86470, "The Effect of Oriented Perforations as a Sand-Control Method: A Field Case Study From the Varg Field, North Sea," by Johan Tronvoll, SPE, SINTEF Petroleum Research; Arne Eek, SPE, Pertra A/S; Idar Larsen, SPE, SINTEF Petroleum Research; and Francesco Sanfilippo, SPE, Oilfield Geomechanics Intl., prepared for the 2004 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.
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.
Fast Method Finds Infill-Drilling Potential in Mature Tight Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 91755, "Fast Method Finds Infill-Drilling Potentials in Mature Tight Reservoirs," by L. Guan, SPE, Texas A&M U., and Y. Du, SPE, New Mexico Inst. of Mining and Technology, prepared for the 2004 SPE International Petroleum Conference in Mexico, Puebla, Mexico, 8-9 November.

Infill drilling plays an important role in improving oil or gas recovery in tight hydrocarbon reservoirs. However, quantifying the infill-drilling potential in these fields often is difficult because of variability in rock quality, well spacing, well-completion practices, and the large number of wells involved. An alternative approach to conduct de-tailed reservoir studies for infill drilling has been developed.

Introduction

One key to ensuring an abundant, economical, and environmentally friendly supply of natural gas is developing the resources in unconventional, low-permeability, tight reservoirs. Although the average production rate of gas wells from these reservoirs is low, they play an important role in the petroleum industry. Infill drilling these reservoirs after initial development (primary and/or secondary) plays an important role in improving the oil and gas recovery. Generally, the effects of reservoir heterogeneity and lack of layer continuity can be reduced with well spacing. Reduced well spacing can enhance the well connectivity.

With the increasing demand for energy and favorable oil and gas prices, more fields are undergoing infill drilling. Advances in reservoir management provide a much clearer picture of hydrocarbon distribution in the reservoirs, which helps engineers plan highly effective well profiles. Advanced imaging technologies allow operators to optimize well placement for infill drilling. It is not uncommon for a company to have many infill candidates to choose from in the tight-reservoir fields. The conventional way to determine infill-drilling potential in a gas basin is to conduct a complete reservoir evaluation involving geological, geophysical, and reservoir analyses and interpretations. As an alternative approach to conducting detailed studies, various empirical or statistical analyses have been used to model variable well performance. The objectives of this work were to study the accuracy of a “fast method” for selecting infill candidate wells in low-permeability gas reservoirs and to provide application guidelines.

Method

This fast method is an extension of the moving-window method. It consists of multiple local analyses, each in an areal window centered on an existing well. However, a more rigorous, model-based analysis is used in each moving domain. The model is based on a combination of the material-balance equation and the equation for pseudosteady-state flow, simplified by assuming that many properties are constant within an individual moving domain. The result is a linear-regression equation that is applied within each window.
Overview: Knowledge Management (October 2005)
Authors: Xiong Hongjie
Published: February 2015

Knowledge management is the way that organizations create, capture, and reuse knowledge to achieve organizational objectives. It is the practice of researching, collecting, and organizing an enterprise’s employees’ knowledge, such as best practices, lessons learned, and know-how.

However, knowledge is not a pure collection (without order) of data and information. Knowledge is part of the hierarchy made up of data, information, knowledge, and wisdom as shown in the figure.

- Data are raw facts (what, who, when, and where).

- Information is facts with context and perspective.

- Knowledge is information with guidance for action (how), such as strategy, practice, method, or approach.

- Wisdom is understanding which knowledge to use for what purpose (why), such as principle, insight, moral, or archetype.

Thus, knowledge is not equal to raw data; instead, it is the fact or condition of knowing something with familiarity gained through experience or association and to be recorded in an individual’s brain or stored in organizational processes, products, facilities, systems, and documents.

“Knowledge is sticky as oil.” Knowledge does not flow without motivation. “Without a systematic process and enablers, it won’t flow.” Oil flows as a result of a pressure difference and permeable channels. Knowledge management provides positive motivation, tools, and an environment to apply knowledge effectively.

In our industry, one of the hot spots of knowledge management is the Internet- and intranet-based application of knowledge management for knowledge sharing and project management, which is growing explosively. These Web-based applications create a very permeable channel for knowledge to flow through, which is similar to creating a highly conductive fracture in the reservoir to speed up and enhance oil recovery. Web-based applications for knowledge management are excellent tools to break barriers between different departments, divisions, and geological regions.

We, as individuals, subconsciously apply our knowledge and wisdom in both professional and personal life. Thus, to an individual, knowledge is an asset, and knowledge is power. However, to an organization, without applications that result from knowledge management, knowledge is neither asset nor power.

So, share your knowledge with others.

Knowledge Management additional reading available from the SPE eLibrary: www.spe.org

SPE 96645 - “Real-Time Information to the Engineer’s Desktop—How Murphy E&P Improved Production Management,” by Oberwinker, C., Real Time Solutions, et al.

SPE 93668 - “En Route to the E-Field: Effective Decision Making Assisted by E&P Web Portal Solutions,” by Giménez, L., Schlumberger

SPE 93279 - “Creative Utilization for Oracle Database To Meet Petroleum Engineering’s Needs,” by Shideed, M.A., SPE, Saudi Aramco

Available at the OTC Library: www.otcnet.org

OTC 17725 - “Digital Energy: The Convergence of E&P, IT, and Communication Systems,” by Schroeder, A.J. Jr., Energy Valley Inc., et al.