bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Lift Optimization for Long-Term Reservoir Simulations
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90506, "Gas Lift Optimization for Long-Term Reservoir Simulations," by Pengju Wang and Michael Litvak, SPE, BP plc, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Although various gas-lift-optimization algorithms have been proposed in the literature, few are suitable for long-term reservoir-development studies that require the gas-lift-optimization process to be highly efficient, flexible, and sufficiently powerful to handle complicated fluid flows and operational constraints. These algorithms also must converge rapidly. The gas-lift-optimization problem considered in the full-length paper is to maximize daily hydrocarbon production by selecting the optimal well-production and lift-gas rates subject to pressure and rate constraints of the surface pipeline network and amount of lift gas available.

Introduction

When oil fields mature, oil production often is assisted by continuous lift-gas injection and constrained by the gas- and/or liquid-handling capacities of surface facilities. The optimal allocation of production rates and lift-gas rates is subject to reservoir deliverability and surface-facility capacities and other capital-investment decisions. Compared to real-time production optimization, the optimal rate allocation in long-term reservoir-simulation studies poses unique problems.

Problem

The optimization problem is to maximize the daily oil production by optimally selecting the well-production and lift-gas rates subject to surface-facility pressure and rate constraints. The optimization problem is considered a well-management problem in a commercial reservoir simulator capable of simulating multiphase compositional fluid flow in reservoirs, well tubing strings, surface pipeline-network systems, and separation facilities.

Integration Procedure. The following is a procedure to integrate the optimization problem into the reservoir simulator.

1. Start with the pressure and fluid com-position in reservoir gridblocks calculated in the previous Newton iteration. Use well lift-gas rates from the previous Newton iteration as the initial guesses.

2. Solve the surface pipeline-network problem; convert pressure constraints to flow-rate constraints.

3. Perform production- and lift-gas-rate allocation optimization.

4. Determine active constraints in wells and nodes. Linearize multiphase-fluid-flow equations for well tubing strings and the surface pipeline network (numerical derivatives are used). Add these equations to the linearized fluid-flow equations for reservoir gridblocks.

5. Solve the linearized system of equations established in Step 4.

6. Repeat Steps 1 through 5 until convergence.

7. Advance to the next timestep.
Technology Update: Technique for Full Modeling of the Multiple Wavefield
Authors: JPT staff _
Published: February 2015

Three-dimensional Surface-Related Multiple Elimination (SRME) has proved a powerful method to address the seismic problem of either reconstructing missing data or reconstructing missing multiple contributions. The specific problems of diffracted multiple energy and out-of-plane (shifted-apex) 3D multiple energy have responded well. Typically, these multiples are caused by rugose or structured seafloors and have proved to be particularly difficult to remove.

Cie. Générale de Géophysique (CGG) has applied the 3D SRME method on projects worldwide with significant benefits. With the approach being based on full modeling of the multiple wavefield, this method is also independent of acquisition geometry, whether 3D streamer with conventional or sparse separation, multi-azimuth, or ocean-bottom cable.

The problem of multiples is approached by use of model-based prediction techniques rather than a data-driven method. The result is a multiple-attenuation technique that fully models the multiple arrivals. The strength of this method lies in its ability to cope with any kind of acquisition geometry.

3D SRME by Surface-Consistent Convolution

Data-driven SRME techniques have recently represented attractive solutions to the multiple problem because they do not require a priori knowledge of the subsurface (reflectivity, structures, and velocities). However, these methods require one shot location for each receiver position, and this is not the case for most 3D acquisition geometries. The most common solution requires interpolation of the input data, thus creating the missing streamers and shot lines for the required prestack convolutional process. The strengths of this approach are that it is fully data driven and models all the multiples at once. However, the surface-consistent convolutions require sampling of identical source/receiver sets; in 3D, this requires significant acquisition and/or data regularization and extrapolation effort (typically, closer sail lines).

3D SRME by Wavefield Modeling

The modeling of the primaries is obtained by prestack demigration of the migrated section (either time or depth). The ringing of the primaries and multiples through the target volume is modeled using the one-way wave equation; as there is a propagated wavefield all along the acquisition surface, the method addresses problems of cable feathering.

Because the shot gathers are modeled separately, the method is suited for parallel implementation. It is currently optimized to run on large personal-computer clusters. For the ocean-bottom-cable environment, each receiver gather is processed separately, and there is no need for sail-line interpolation (or receiver-gather interpolation).
Management: Identifying, Preserving, and Defending Trade Secrets
Authors: Warden David E. , Phillips Joe
Published: February 2015

Reported trade secret the ft: 323% rise in the United States during the 1990s (Whaley 1999).

Annual employee turnover in business and professional services: more than 21% (Essex 1993).

These cautionary statistics, along with the currency of information in funding global success, require sophisticated businesses to routinely address the unwanted disclosure of trade secrets. Balanced against businesses' desire to prevent this disclosure are the policies of free competition and the employee's right to apply his skills and knowledge. Within this tension lies a body of law—preventive and compensatory—that technologically intense and information-dependent oil and gas companies should know.

The discussion that follows deals with trade secrets in the context of U.S. law, but many other countries have comparable underlying concepts. The Treaty of Rome, governing the European Union, similarly provides that a trade secret is something not generally known or easily accessible (Van Arnam 2001). English jurisprudence protects trade secrets in much the same way as they are protected in the U.S. but through court-made law rather than statutes (Lipton 2003). Japanese law parallels U.S. law by protecting technical or business information useful in commercial activities and that is kept secret and not publicly known (Harris 2002). China also defines a business secret as technical and operational information that is not known to the public, is capable of bringing economic benefits to the owners, has practical applicability, and has been subjected to measures to keep it secret (Bejesky 2004). The U.S. definition of a trade secret is mirrored in key international agreements: the World Trade Organization's Agreement on Trade-Related Aspects of Intellectual Property Rights and the North American Free Trade Agreement.

Nonetheless, this property right and punishment for its violation can differ across nations in important ways. Criminal law, in particular, may diverge on remedies, the elements of proof, and the right to seek relief. Useful analysis of law outside the U.S. and of international agreements can be found in Melvin F. Jager's Trade Secrets Throughout the World (1994) and his Trade Secrets Law (1985) and in D. Campbell's World Intellectual Property Rights and Remedies (1999).
Overview: Formation Evaluation (May 2006)
Authors: Kennedy Martin
Published: February 2015

Next year will mark 80 years since the Schlumberger brothers ran the first wireline log. Geophysical mapping, in particular surface seismic, had a slightly earlier and arguably more protracted birth. Both ways of extracting information from the subsurface have been refined and extended considerably since then, of course; but fundamentally, we are stuck with just two sources of data, both of which have shortcomings. I recently have taken to taunting geophysicists by likening seismic images to photographs that have been taken through the bottom of a brandy bottle (and I mean French five-star Cognac, which comes in bottles made of very dark glass with a huge conical dimple in the bottom). On the other hand, logs and other data from wells can tell you almost anything you want to know about what is going on at or a few centimeters from the borehole wall, but give no direct knowledge of the remaining 99.999…% of the field.

There is not much to fill the gap between geophysics and well data—or is there? I believe there is, and some of it has been around for a long time. One can list several mature bore-hole measurements that will see tens or even hundreds of meters into the formation:Deep-reading resistivity tools—50 years old.Vertical seismic profiles—40+ years old.Borehole gravity—40 years old.

Given two or more wells, tomography becomes a possibility as well. No one should be under any illusions that these measurements are easy to make or interpret. Typically, they involve modeling and, therefore, require time and a reasonable idea of what is in the subsurface. In short, they are appraisal tools.

Accurate placement of development wells frequently requires deep-reading measurements made in real time. Resistivity may be appropriate, but this method presupposes the existence of a resistivity contrast at the boundary that is controlling the well path (a gas/oil contact fails the test, for a start). There are convincing demonstrations that sonic measurements can image boundaries at useful distances from the well, but it is a formidable challenge to turn that technology into a real-time technique. Formidable, yes, but I would be surprised if it turns out to be impossible.

Formation Evaluation additional reading available at the SPE eLibrary: www.spe.org

SPE 95950 "What Is the Characteristic Length Scale for Permeability? Direct Analysis From Microtomographic Data," by F. Bauget, Australian Natl. U., et al.

SPE 96100 "Measurement of the Sealing Capacity of Shale Caprocks," by T.M. Al-Bazali, SPE, U. of Kuwait, et al.

SPE 96609 "NMR and Capture Spectroscopy Help Resolve Producibility and Fluid Distribution in the North Alwyn Triassic," by C. Longis, Total E&P, et al.

IPTC 10726 "Applications of Petrophysical Scale-Reconciliation to Saudi Arabian Reservoirs," by H.A. Al-Ali, SPE, Saudi Aramco, et al.
Use of Wet Shale and Effective Porosity in a Petrophysical Velocity Model
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17643, "Using Wet Shale and Effective Porosity in a Petrophysical Velocity Model," by A. May, Kerr-McGee Corp., prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.

Sonic logs can be improved by use of a petrophysical model to create theoretical compressional and shear waves. The measured sonic logs are used only as a guide. Measured sonic logs are subject to serious error resulting from borehole conditions and invasion. When the results of a petrophysical velocity model are used to compare wells to seismic or to build a rock-strength model for pore-pressure prediction or a well completion, the results usually are better than with the measured data alone. One debate is about how to add porosity and what porosity to use. Many petrophysicists prefer to use total porosity and volume of dry clay to build models. This author prefers to use effective porosity and wet-shale volume.

Introduction

Petrophysical velocity modeling, to improve sonic logs and create better well ties to seismic sections, is important today for both amplitude-variation-with-offset studies and seismic inversions. These petrophysical velocity models begin with a petrophysical interpretation that describes the rock components. The interpretation provides the volumes of sand, shale, carbonate, and other components in the solid matrix, as well as the porosity of the rock and a description of the fluids filling the rock's pores. This description is used to compute compressional sonic velocity and shear sonic velocity. Various methods can be used to make these calculations, but great care must be taken to make certain that the volume definitions used in the petrophysical interpretation are the same as those used in the velocity model. This admonition is particularly important for the definitions of shale and porosity.

Wet Shale

The techniques for producing and presenting petrophysical interpretations fall into two categories, the wet-shale/effective-porosity method and the dry-clay/total-porosity method. In both models, total porosity is the same. The wet-shale model, which also can be called a rock model, divides the rock into two components: sand and shale. These are not minerals, but rock components. In this model, the shale has bound water associated with it according to a shale porosity determined by the log response of a "type shale" chosen by the analyst. The effective porosity is the porosity in excess of the shale porosity. The effective-porosity portion of the rock contains irreducible water associated with the sand and silt that depends on the height above the hydrocarbon/water contact, or capillary pressure.
Overview: Artificial Lift (May 2006)
Authors: Scott Stuart L.
Published: February 2015

For the past several decades, artificial lift has referred to the traditional technologies of downhole pumping (e.g., sucker rod, electrical submersible, progressing cavity, and others) and gas lift. Today, a broader definition is emerging, a definition that can encompass the fundamental changes occurring in our industry. Today, artificial lift is no longer limited to methods applied in the wellbore, but instead must include methods used throughout the production system to "lift" the produced fluids to their final destination.

For example, gas and heavy oil constitute a much larger portion of today's energy mix, driving significant changes in development philosophies. Today's heavy-oil developments make extensive use of multiphase production with long multiphase flowlines to tie wellsite production back to centralized processing facilities. Pressure losses in the surface multiphase gathering system can be significant, and a combination of downhole pumps and surface multiphase pumps often is required to effectively "lift" the fluids to the processing facility. Key issues for heavy-oil artificial lift include handling produced sand, increasing volumes of gas, and the high temperatures associated with thermal recovery projects.

The booming natural-gas business has focused attention on artificial lift in gas and wet-gas developments. At the surface, wet-gas gathering systems have been found to provide advantages in terms of reduced capital expenditures and complexity. In this case, an important component of artificial lift is the boosting of the wet-gas stream through surface flowlines, which in the future may take the form of multiphase pumps and wet-gas compressors. In the wellbore, problems associated with lifting liquids from gas wells are well known. Today, several newer methods are being applied, such as the combination of flow-enhancement chemicals (e.g., surfactants) with downhole flow-enhancement tools.

Deep water, ultradeep water, and other remote resources also have forced a broader definition of artificial lift. For deepwater and ultradeepwater developments, flow in risers and long subsea flowlines represents an important component of the production system. Intervention issues associated with subsea wells severely limit application of wellbore artificial-lift methods. Therefore, artificial lift is increasingly taking the form of seafloor multiphase-pumping and riser-lift methods.

When searching for an artificial-lift solution, a wide variety of methods now must be placed "on the table" alongside the traditional methods we have used for decades.

Artificial Lift additional reading available at the SPE eLibrary: www.spe.org

SPE 95620 "ESP Model Implementation and Result Analysis Under Gas/Liquid Flow Conditions," by D. Sun, SPE, Baker Atlas, et al.

SPE 97275 "Effect of Operating-Valve Performance on Stability of Gas Lift Wells," by Y.V. Fairuzov, SPE, Natl. Autonomous U. of Mexico, et al.

SPE 93594 "Electrical Submersible Progressing-Cavity-Pump Application in Kulin Horizontal Wells," by M. Taufan, SPE, P.T. Caltex Pacific Indonesia, et al.
Pilot Capillary Surfactant-Injection System in the San Juan Basin
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 94293, "Downhole Capillary Surfactant-Injection System Pilot on Low-Pressure Gas Wells in the San Juan Basin," by J.P. McWilliams, SPE, and D. Gonzales, SPE, Burlington Resources, prepared for the 2005 SPE Production and Operations Symposium, Oklahoma City, OK, 17–19 April.

Depletion of San Juan basin reservoirs is causing production rates to drop below the rate required for the minimum critical velocity (MCV) in a large number of wells. Traditional methods used to remedy this situation include plunger lift, pumping units, foam lift, and recirculation. With declining reservoir pressures, plunger lift and recirculation become less effective, and often the expense of purchasing and operating a pumping unit cannot be justified. In some cases, surfactant injection may offer the most cost-effective fluid-removal method.

Introduction

As gas reservoir pressures are depleted and production rates decline, liquid loading becomes a problem. When flow rates fall below the MCV, liquid accumulates in the wellbore, causing additional backpressure on the formation that reduces production rates. A downhole capillary surfactant-injection system (DCSIS) has been shown to aid in removing these fluids. The DCSIS delivers surfactant directly to the bottom of the wellbore where it is needed to be effective. A stainless-steel capillary-tubing string is run in the wellbore and is attached to a fluid pump and a chemical-storage tank. Once installed, a metered amount of surfactant is injected downhole to help unload the well.

Promising results were seen from installation of a DCSIS on a slimhole well in the San Juan basin. A 10-well pilot was proposed to test the system. Initial criteria for the pilot required that a well be experiencing liquid loading and that all other artificial-lift methods had been ineffective or were uneconomic. The primary objective of the pilot was to determine the best applications for the system in the San Juan basin.

Foam Flow

Surfactant injection reduces density, gas slippage, and surface tension of the liquid/surfactant mixture. Most attempts to model the MCV required to lift foam to the surface are based on the Turner model, which is based on drop-entrainment mechanics. The Turner model calculates the velocity required to lift the largest liquid droplet to the surface. This velocity is a function of the liquid-drop density and diameter, gas-phase density, drag coefficient, and acceleration resulting from gravity.

Typical values for surface tension and liquid density are 60 dynes/cm and 67 lbm/ft3, respectively. However, proper surfactant treatment can lower the surface tension to less than 40 dynes/cm and also reduce the density significantly. Because the Turner model is based on the physical properties of a water droplet, some assumptions made by Turner probably are not valid for foam flow.
Petroleum Industry 2020: Celebrating Around the World
Authors: Al-Khalifa Abdul-Jaleel
Published: February 2015

There are milestones in nations' histories and humans' lives. The 50th anniversary of the SPE is certainly a major milestone for more than 73,000 members. It is a milestone of a dream that became a reality. It is a success that followed 50 years of vision, hard work, and dedication. It is a culmination of a global team effort that involved staff, members, and industry at large.

SPE members have already started the journey of celebrating the 50th anniversary of the SPE in various locations around the globe. The first celebration was held in Bahrain along with the Middle East Oil Show, then in Cairo along with the SPE Board of Directors meeting, and lately in Buenos Aires during the Latin America and Caribbean Petroleum Engineering Conference. The plan is to hold celebrations in many other locations, ending with the Annual Technical Conference and Exhibition (ATCE) in Anaheim, California, in November this year. All SPE sections were also invited to celebrate this memorable and momentous occasion.

SPE Bright History

As we all celebrate this event, let's reflect on SPE's bright history and prospects for a promising future. Over the past 50 years, SPE membership grew six fold, from 12,500 to more than 73,000 members. Membership services, publications, and meetings have significantly evolved to meet the exploding needs of both scope and geography.

SPE's mission to collect and disseminate technical information is well served. The Society currently holds more than 70 events, hosting more than 150,000 attendees on an annual basis. The publication of five peer-reviewed periodicals has met the aspiration of intelligent scientists and engineers to share their knowledge and best practices. JPT brings members a broad overview of the latest technical advances each month. Talent & Technology is a recent add-on to the JPT, highlighting the importance of talent in our industry. The eLibrary, an industry first, also presents a golden treasure of 42,000 technical papers available 24 hours a day, 7 days a week around the globe.

SPE is an International Society

The transformation of SPE from a U.S. organization into an international society marks a significant evolution. This process has taken many years of planning and hard work. Now, about half of SPE's members live outside North America. SPE offices are located across the globe, in Dallas, Houston, London, Dubai, and Kuala Lumpur. A new office is being planned in Russia. A special focus on Africa, China, and Latin America will hopefully develop into increased membership and more events in the near future. In 2010, the ATCE will be held for the first time outside North America, in Florence, Italy. It will then alternate between North America and other locations. SPE continues to transform into a borderless organization that breaks the walls of time and space. SPE thrives on excellence and diversity that transcends color, race, faith, and gender. It draws on love and respect as the most bonding relation among all SPE members.
Management: Information Security: Risk and Reward
Authors: Gauci Donald
Published: February 2015

Information security is the bedrock of any information risk-management system, and oil and gas companies are becoming more adept at minimizing risk by bolstering these systems across their organizations. Information technology (IT) is becoming such an important facet to these businesses and their disaster-recovery and business-continuity planning that the security issues now often spread to the upper echelons of many organizational charts, even to boards of directors and audit committees.

In fact, the industry is seeing an increase in the number of executives in charge of company IT assets. Such arrangements play a powerful role in IT security and can result in strategically aligning IT-security issues with business objectives. Oil and gas companies should evaluate the following as global priorities when assessing information security:Integrating information security within the organizationExtending the impact of complianceManaging the risks of third-party relationshipsFocusing on privacy and personal-data protectionDesigning and building information security

Some of the regulatory changes that have taken place over the last few years, particularly related to the Sarbanes-Oxley Act in the United States, have caused companies to move from a reactive to a more proactive mode. While many energy companies still would rather spend capital on commodity assets than on information assets, they are slowly shifting as they recognize that information security is a top business driver. IT security is becoming a part of the discussion in the context of a company's priorities. Whether those priorities include adding new acreage or adding rigs, E&P companies are leveraging technology more and more, and, as that technology is leveraged, the need for IT security rises.

As Technology Is Leveraged, Risk Rises

As companies grow through expansion or from mergers and acquisitions, computer networks can multiply and expand like cell division. Gradually adding bits and pieces to a network, especially when knowingly or unknowingly commingling sensitive data, increases risks and elevates the need for IT security. Not long ago, petroleum engineers, for example, examined geology assets in a back room, working safely within a secured computer network. Today, more and more of these professionals are performing such work on broader company networks, a move that saves companies money, but also elevates the possibility of data being compromised.

The notion of E&P companies leveraging communications technologies is not new, but they are constantly breaking new ground where applications are concerned. Fiber-optic networks, for example, are commonplace, and energy companies are now investing billions of dollars to lay these systems in the Gulf of Mexico and at other offshore asset locations. They know that as they go out into deeper water, the fiber-optic network will offer better communications capabilities for current and future processing facilities and drilling activities.
Dynamic Depth Correction To Reduce Depth Uncertainty and Improve MWD/LWD Log Quality
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 103094, "Dynamic Depth Correction To Reduce Depth Uncertainty and Improve MWD/LWD Log Quality," by D. Dashevskiy, SPE, T. Dahl, A.G. Brooks, SPE, D. Zurcher, J.C. Lofts, SPE, and S. Dankers, SPE, Inteq, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

Accuracy of measurement-while-drilling (MWD) and logging-while-drilling (LWD) depth measurements can be improved by considering the dynamic variation in drillstring length caused by pipe loading under changing drilling conditions. A new method that uses surface torque, hookload, and temperature measurements was developed to determine force distribution in a drillstring and to compute apparent drillstring length. When available, downhole measurements of torque, weight on bit (WOB), and temperature are used to increase accuracy and robustness of the method.

Introduction

With longer and deeper wells in deeper provinces around the world and the use of drillpipe conveyance of MWD/LWD data, accurate depth measurements are critical. Depth accuracy is vital for calculating structural dip from borehole images, picking perforation points, and correlating geological units. Measured depth (MD) is used directly in the calculation of true vertical depth (TVD) (the primary depth used for reservoir delineation).

Errors in depth are difficult to detect with a single scalar measurement; however, comparing several logging curves with similar character (Fig. 1) can reveal these artifacts. Cross correlation and a depth "rubber-banding" technique are used to bring MWD/LWD measurements from different sources (even within the same bottomhole assembly) together, using measurements from the sensor nearest the bit as a reference. This method addresses the symptom, not the cause. Misalignment of curves serves as a good indicator of the formation-evaluation (FE) -measurements depth-placement uncertainty and should be used instead for validation of methods used to convert MWD/LWD data to depth logs.

Background

All data from MWD/LWD tools are referenced to time. The moment in time when every measurement value was taken is known. However, it is necessary to know where the measurement was taken. To determine where measurements are taken, the following are needed.The wellbore profile—wellbore location in space.The time/depth profile—the location (with respect to the wellbore) of the bit at each moment in time.

This information can be used to place MWD/LWD measurements along the wellbore and, hence, in space. The assumption that the time/depth profile represents the TVD of the bit (and hence logging-sensor depths) at any moment in time often is incorrect. Bit depth is seldom equal to the summation of lengths of all steel run in the hole and the hook-height displacement, in part because of forces acting on the string that cause pipe to stretch, compress, or buckle. All errors in measuring time and depth will affect the quality of MWD/LWD logs.
The Status and Future of Remote and Automated Drilling Techniques
Authors: Ogg Jeremy
Published: February 2015

Technology Update

The drilling industry is on a diving board looking down at automation, and we in this industry are currently deciding whether to join the other industries in the pool. We know that our industry will not be the first to embrace automation, and we also know that we are surrounded by other industries whose application of automation is proving, or has already proved, to be successful. Automation has been so successful that it has breathed new life into these industries, often revitalizing the way they supply their product. The results are generally a larger volume of product supplied faster, with fewer errors, and with more process standardization. Does this sound familiar?

Remote Linking and Real-Time Modeling

A number of automated products and services are making headway in the drilling industry, and this article will focus on two technologies of note.

DrillLink, developed by National Oilwell Varco (NOV) / M/D Totco, is a remote-linking automated control technology consisting of a device that facilitates the transmission of remote signals to the control system of a conventional drilling rig (Fig. 1).

Drilltronics, developed by the International Research Institute of Stavanger (IRIS) and NOV, is a drilling information technology that performs real-time modeling to improve drilling efficiency significantly (Fig. 2).

Logically, a crucial step in the drilling-process automation will occur as these types of technologies become capable of providing input for the other's output—where instructions can be communicated from one device to another to dictate operations. Are we at that point now? No. However, all the parts are developing that will make the whole. Conceptually, before we can automate commands on the basis of modeling, it first is necessary to determine whether commands derived manually can be automated.

Automated-Command Technology Tested

In 2004, MD/Totco and Schlumberger successfully drilled at a test rig in Cameron, Texas, by means of commands sent from Cambridge, UK, using the remote-linking automated control system already described. Achieving 100% success with the communication protocol, the Cambridge scientists were able to successfully control the weight on bit, flow rate, and the revolutions per minute of routine drilling operations of a rig more than 4,500 miles away.

Fundamentally, this technology places a communication box between the existing throttle signal from the drill-floor and the input to the power-control system that drives the rig. This box provides a means for the driller to allow control by a remote directional driller, regardless of whether the directional driller is at the rigsite or in an office anywhere on the globe. The driller remains in control, setting a maximum throttle that cannot be exceeded by others. Additionally, the driller has the ability to override the directional driller's signal at any time simply by changing the throttle on the console or turning off the linked system, thereby ensuring that ultimate control always remains on site.
Evolving Subsea Technology Tackles Huge New Risks of Today's Projects
Authors: Parshall Joel
Published: February 2015

As oil and gas development projects tackle some of the world's most remote locations and extreme environments, pushing out into 8,000 ft water depths or beyond and going several hundred miles offshore, innovations in subsea technology will play a vitally important role in enabling the execution of these projects and will form the basis of future, even more-ambitious plans.

Subsea technology comprises wellhead and related production infrastructure placed on the seafloor, rather than on a conventional surface platform, a spar, or a semisubmersible or other floating production facility. Subsea wells and infrastructure are tied back by flowlines, risers, and umbilicals to surface producing facilities that may be directly overhead or many miles away, possibly even onshore.

While deploying subsea technology can be very expensive, as water depths increase, conditions grow harsher, and locations become more remote, the alternative of building a larger, heavier surface facility to hold the wellheads, pumps, separation equipment, and other infrastructure is often more expensive, sometimes prohibitively.

"There are two things that drive much of the move toward subsea," said David Morgan, Director, Subsea Processing, Cameron. "One is cost, the other is the reservoir. Typically, you must have at least one surface facility for drilling, processing, or storage. But surface facilities are a huge expense, and reservoirs sometimes are very spread out, making it hard to drill from one surface facility. That starts to drive multiple drill centers or the move to subsea development. By minimizing the size and number of surface facilities, you can save your project a lot of money."

On the one hand, when equipment is placed on a surface facility, maintenance and interventions typically are conducted from that facility, and costs are easier to project and control—compared with contracting costs for a rig or vessel to service subsea equipment. On the other hand, space is at a premium on any kind of floating facility, and the need for additional equipment (e.g., separation, water-handling, and compression facilities) as a project matures is difficult to accommodate by retrofitting late in field life. By installing the additional equipment subsea, the need for platform changes can be minimized.

"How effective we are at developing subsea technologies and evolving existing technologies is going to be an indication of how successful we are in recoverable reserves and maintaining our increasing production globally," said Neil Holder, Vice President, Sales and Marketing, Aker Solutions. "More and more companies are looking at stranded gas, offshore oil, and resources in the Arctic with long tieback distances that without subsea technology can't be accessed at all. So it becomes a facilitator."
Autonomous Systems Improve Production
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112078, "Improving Production by Use of Autonomous Systems," by Jorn Olmheim, Einar Landre, SPE, and Eileen A. Quale, SPE, StatoilHydro, prepared for the 2008 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 25-27 February. The paper has not been peer reviewed.

Several companies have reported a 2 to 5% increase in oil production, and in some cases up to 10%, by use of a closer collaboration between onshore-based production-optimization groups and offshore personnel. The concepts of variable and delegated autonomy from the domain of unmanned flight were applied in StatoilHydro's production process. Compared with traditional automation, the concepts of delegated and variable autonomy introduce negotiation between different subsystems and a more-adaptable human/machine interaction.

Introduction

The industry trend is toward increased instrumentation and the use of smart-well technology for new developments. This trend has increased information flow into the control room, presenting new challenges with respect to use of this information. Other industries have shown that increased information flow can contribute to information overload and lack of shared-situation awareness between key stakeholders.

In the control room of a large installation with 100 wells and each well producing 15 different signals, 1,500 different signals must be processed at any given time. Humans are not able to process this flood of data rapidly and efficiently. An objective of integrated operations is better use of technical experts, independent of location. Therefore, shared-situation awareness between control-room operators and remote experts is a pre-requisite. Achieving the required level of situation awareness can be assisted by an increased level of computerized support that is able to analyze complex data streams and transform raw data input into events and derived recommendations for further analysis and action.

Production Practices and Challenges

Production planning is based on an agreed production target or profile, in accordance with the field's drainage and injection strategy, or on a delivery-contract obligation. The individual well's contribution at any given time will depend on the required production rate as well as other factors such as limitations on wellhead or downhole pressure, sand-production potential, equipment restraints, coning/cusping conditions, and velocity restrictions. Also, total production to a facility will be dictated by the available handling capacity for the different fluid phases and export requirements, as well as by necessary maintenance work. A facility's production profile generally will be characterized as "well-limited" (well potential is the limiting factor) or "process-limited" (the production facilities are the bottleneck).
Connector/Conductor Wells: Multiple Wellbores With Downhole Connections
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 111441, "Connector-/ Conductor-Wells Technology in Brunei Shell Petroleum Achieve High Profitability Through Multiwellbores and Downhole Connections," by Shaikhan Al- Khodhori, SPE, Petroleum Development Oman; Hamoud Al-Riyami and Philip Holweg, SPE, Brunei Shell Petroleum; and John Wright, SPE, John Wright Company, prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.

Connector/conductor (CC) wells were implemented in Brunei. The conductors (feeders) are horizontal wellbores drilled through the oil rims, with the section of the wellbore above the top of the reservoir abandoned. These conductor wellbores act as horizontal flow conduits in the reservoir. Production to the surface is through dedicated connector (producer) wells designed to connect several conductor wellbores and provide shared completion equipment to surface. Success of the Darat CC-wells project proved technically feasible for implementation in other fields.

Introduction

The Champion West field has several oil rims that are displaced vertically and laterally from each other. The volumes in these rims are too small to justify a dedicated producing well for each rim. The CC-well concept shown in Fig. 1 was proposed to develop these marginal oil rims. Also, it was recommended that the concept be proved further in the Darat asset before full implementation in the Champion West field because Darat is a lower-cost environment, has less-complicated subsurface features compared with Champion West, and has existing suspended exploration wells for intersection and connection.

Fig. 2 shows the plan for the Darat CC well, where Well S-840 is a land well acting as the connector and Well S-833 is an offshore well acting as the conductor. Well S-833 was drilled at the end of 2005 and completed in November 2006, with two gravel-packed completion zones. The Darat CC well was to prove the following.The ability to "home in" and achieve a close proximity with the existing well of less than 40 cm at approximately 90° incidence angle without a plugback.The ability to connect the two wells (conductor and connector) mechanically and hydraulically and sustain sufficient flow through the connection.

Two technical challenges or key technology areas that were critical for success were improving ranging accuracy and making a hydraulic connection between the two wellbores.

Technical Solutions

Homing-in and Bypass Strategy.

Borehole-surveying instruments [e.g., measurement-while-drilling (MWD) and gyro technology] do not have sufficient accuracy to achieve the required trajectory and proximity to make a perforated connection. To close this gap, homing-in or ranging technology would be required. Two techniques were selected: single-wire guidance sys-tem (SWGS) and rotating-magnet ranging system (RMRS).
Real-Time Fiber-Optic Casing Imager for Continuous High-Resolution Casing Monitoring
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 109941, "Real- Time Fiber-Optic Casing Imager," by M. Appel, SPE, D. Dria, SPE, J. Freeman, F. Rambow, SPE, and M. Shuck, SPE, Shell Intl. E&P, and B. Childers, S. Poland, SPE, and T. Dominique, Baker Hughes, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. The paper has not been peer reviewed.

During the last few years, significant progress has been made in the use of fiber-optic technology for well and reservoir surveillance. The full-length paper details recent advances in development of a real-time fiber-optic-based casing imager that is designed for continuous, high-resolution monitoring of tubular shape and enables determination of strain imposed on the tubulars. Small-scale and full-casing-size laboratory tests have demonstrated that the latest generation of this system is sufficiently sensitive to detect casing deformations of less than 10°/100 ft and covers compressive and tensile axial-strain ranges from less than 0.1 to 10%.

Introduction

In many regions of the world, regular monitoring of casing deformation needs to be an essential part of the reservoir-surveillance program because reservoir compaction and other geological conditions can impart significant loads on casing, which can lead ultimately to loss of the well. By monitoring the shape of the casing or the strain imposed on the casing, data may be available at a sufficiently early stage to enable remedial actions to prevent casing damage. Continuously monitoring casing deformation in real time improves the understanding of compaction and other strain-related reservoir conditions, which is essential for optimizing production and reserves recovery.

Subsurface compaction and stress-change behavior can be investigated remotely by use of several indirect-measurement techniques. On land, subsidence monitoring in combination with microseismic detection, supported by tiltmeters and data derived from global-positioning systems, has been used to characterize reservoir compaction. Microseismic, seafloor pressure gauges, and seafloor tiltmeters give indications of changes occurring on the seafloor and subsurface. More recently, reservoir changes have been analysed using time-lapse-seismic techniques.

Real-Time Casing Imager (RTCI)

Considering the limitations of traditional in-well monitoring, a measurement technique was developed to measure real-time distributed strain and temperature along a well tubular with a very high spatial resolution. The technology is called RTCI and is based on fiber-optic technology. The main components of the RTCI include the following.A sensing fiber-optic cable attached to downhole equipment.A fiber-optic lead-in cable that would be run in the well with the downhole equipment and enables sending laser light to the sensing element of the fiber-optic cable.A surface interrogation unit designed to provide the laser light and to analyze detected signals.
Technology Focus: Wellbore Construction (May 2008)
Authors: Gonzalez Manuel
Published: February 2015

Technology Focus

Well construction involves many disciplines, including casing design, tubing design, downhole-completion equipment, cementing, perforating, and, finally, stimulation. All of these things must be designed and implemented to build a successful economical well. However, the vast majority of the 2007 SPE well-construction papers were cement-related. Because cementing appears to be a recent, but strong, trend, I asked one of Chevron's cementing experts (Robert Carpenter) for his opinion. Below, he talks about why cementing for completions has become a hot topic.

"This is evidence of the growing realization that long-term isolation involves more than just pumping some cement spacer and 3,000-psi cement. People are beginning to recognize the stresses placed on the cemented annuli and to grasp the effect of the stresses on long-term annular isolation. We see this in the number of papers by service companies, universities, and now operators relating this concept and their experiences developing and applying cements with greater elasticity and/or self-healing properties.

The trend is to use more-elastic-cement designs to prevent tensile-stress-induced microfractures; more recently, one can add cement with self-healing properties. The big interest in recently developed swelling packers also is part of this trend. Newly developed, expanding packers are being used instead of cement and/or to supplement cement to ensure long-term isolation.

This trend results from several factors: rising cost of well construction (particularly in deepwater applications) and remedial work, deferred/lost production, and an increased focus on environmental and safety issues. The industry wants to avoid the cost and liability of future annular leaks and sustained casing pressure. All have combined to foster an increased development and adoption of technology to improve long-term annular isolation during well-construction and production operations. On another front, there has been an increased focus on cost-effective remediation and return to service of shut-in or leaking wells. Several of this year's papers detailed large-scale remedial-cementing programs and diagnostic methods used by several operators."

My thought is that it does no good to drill a USD-100-million well if, in the end, we cannot isolate the zone of interest.

Wellbore Construction additional reading available at the SPE eLibrary: www.spe.org

SPE 108973 • "Multitype Application of Cement Packer: Simple and Economical Method of Accessing Bypassed Reservoir Potential" by Muhammad Idris, SPE, Vico Indonesia, et al.

SPE 105413 • "Cementing Considerations for Casing While Drilling: Case History" by Robert D. Strickler, SPE, ConocoPhillips, et al.

SPE 106765 • "Field Study Results Improve Squeeze-Cementing Success" by Michael Cowan, Shell International E&P.