bluuebunny/crossref_metadata_2025_split 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.