bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimal Coarsening of 3D Reservoir Models for Flow Simulation
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 95759, "Optimal Coarsening of 3D Reservoir Models for Flow Simulation," by M.J. King, SPE, K.S. Burn, P. Wang, V. Muralidharan, SPE, and F. Alvarado, BP America Inc., and X. Ma, SPE, and A. Datta-Gupta, SPE, Texas A&M U., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.
A new constrained optimization approach to the coarsening of 3D reservoir models for flow simulation has been developed. The optimization preserves a statistical measure of the heterogeneity of a fine-scale model. Constraints arise from the reservoir fluids, well locations, pay/nonpay juxtaposition, and large-scale reservoir structure and stratigraphy. The approach has been validated for several oil and gas projects in that flow simulation through the coarsened model was shown to provide an excellent approximation to high-resolution calculations performed in the original model.

Introduction
The development of coarsened reservoir-simulation models from high-resolution geologic models remains an active field of research. This study had success with the use of coarsening algorithms to determine a reservoir-simulation grid obtained by grouping fine-scale geologic-model cells into effective simulation cells. Results differ from previous studies in that a statistical analysis of the static properties of the model appeared to identify the best grid for dynamic reservoir simulation. Coarsening beyond the degree indicated by the analysis discarded too much of the underlying heterogeneity. It would overly homogenize the properties on the simulation grid. Finer models would retain at least as much reservoir heterogeneity, but they are more costly.
This analysis uses a statistical technique for layer grouping and a constrained approach for areal gridding. The resulting composite corner-point grid (CCPG) has many of the advantages of unstructured perpendicular-bisection grids in that it can follow major features of the geologic description. Compared with perpendicular-bisection grids, CCPGs have exact alignment of the simulation cells with the geologic model, which will minimize property-scaleup errors, and they may be used without the development of new simulation pre- and post-processing applications. This approach also moves closer to having an Earth model shared between the reservoir engineer and the reservoir geologist: The 3D geologic model will provide the grid on which the high-resolution initialization of the simulation model will be calculated.
The full-length paper details the new statistical approach applied to layer coarsening followed by unstructured vertical coarsening and volumetric coarsening.

Layer Coarsening
Static methods are fast. Unfortunately, they do not predict the appropriate number of layers for a dynamic model. The dynamic model must be tested by simulation and the appropriate number of layers determined by trial and error.
Erha and Erha North Development
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18655, "Erha and Erha North Development: Overview," by T.C. Parker and A. Sofidiya, SPE, ExxonMobil, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
In March 2006, ExxonMobil affiliate Esso E&P Nigeria started production from the Erha deepwater development approximately 97 km offshore Nigeria in 1200 m of water. The Erha development includes Erha North, a satellite development that came on stream in September 2006. The Erha and Erha North Project consists of 32 subsea wells tied back to a floating production, storage, and offloading (FPSO) vessel. A catenary-anchor-leg-mooring (CALM) buoy is used for crude-carrier docking and product transfer.

Introduction
The first exploration well, Bosi-1, was drilled on the block in 1996. The Erha oil discovery was made with the Erha-1 well in February 1999. Appraisal well Erha-2 was completed in November 1999, and the Erha-3 appraisal well and sidetrack were completed in September 2001. Well Bosi-2 discovered oil in March 2002. After the start of Erha development drilling, an oil discovery was made in March 2004 with Well Erha-7 and Erha-7 sidetrack, leading to the addition of a third drill center, Drill Center North (DCN). Recoverable reserves are estimated to exceed 7.9×107 m3 of oil.
The Erha and Erha North plan included sequential startup of three drill centers, managed simultaneously with a two-rig development-drilling program and ongoing production operations. The subsea wells are connected to a new-build, spread-moored FPSO through flowlines and steel catenary risers (SCRs). Processing facilities installed on the FPSO handle 3.3×104 m3/d of oil, as well as provide injection capability for 2.4×104 m3/d of water and 9.6×106 std m3/d of gas. Processed crude oil is stored in the FPSO and periodically offloaded to trading tankers through a CALM offloading buoy.

Development Planning
Initial development plans focused on selecting a development concept for the Erha field N4 resource with flexibility to accommodate future tiebacks to commercialize additional discoveries on the block. The development concept captured and incorporated learnings from ExxonMobil's worldwide project execution, with particular emphasis on other west Africa projects, technology, and operability.
The original Erha full-field development plan included 24 subsea wells, clustered in two drill centers: Drill Center East (DCE) and Drill Center West (DCW). All subsea wells would be drilled and completed from a mobile offshore drilling unit (MODU) and tied back to the FPSO. Producing wells would be brought together through manifolds with insulated flowlines and risers connecting the manifolds to the FPSO. All gas-injection wells would be over the gas cap from DCE, and water-injection wells would be from DCW. Injection wells at each drill center would be routed through a manifold connected to the FPSO with a single uninsulated flowline and riser.
Global Optimization and Uncertainty Assessment for History Matching the Valhall Field
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 100946, "History Matching of the Valhall Field Using a Global- Optimization Method and Uncertainty Assessment," by B.R. Al-Shamma, SPE, Imperial College, London, and R. Teigland, Total E&P Norge, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
A study was made of a global-optimization method to history match a complex reservoir model. Evolutionary algorithms (EAs) were applied, and methods for improving the convergence of the optimization cycle were used. Sensitivity parameters, correlations, and parameter trends were identified in a global search space, and an uncertainty assessment of the most recent history match was carried out with an experiment-design matrix.

Introduction
The focus of this study was to assess the Valhall field reservoir-simulation model by use of EAs and uncertainty assessments to improve the manual history match of the model. The Valhall field is complex with rock compaction as the main drive energy, which contributes to many challenges, including the reduction of porosity (Ø) and permeability (k) with time and continued change of reservoir thickness caused by the compaction. The compaction can affect different parts of the reservoir differently. For example, the reduction in the pore volume can vary between regions, resulting in problems with the history-matching process in which changing a particular parameter can have opposite effects on wells or regions. Fig. 1 shows the workflow used for uncertainty assessment.
The Valhall field is an oversaturated Upper Cretaceous chalk reservoir in the North Sea approximately 290 km offshore Norway in 69 m of water. Discovered in 1975, oil production began in 1982. Oil originally in place was estimated at 4.3×108 m3. Total production at the time this paper was written was 7.9×107 m3 of oil equivalent. The primary reservoir is the Tor formation, with a secondary reservoir in the Hod formation. The thickness of the Tor formation varies, abruptly ranging from 0 to 80 m. Approximately 50% of the drive to date has been from rock compaction, observed by porosity reduction in infill wells. The porosity is greater than 50% in some places; some fractured permeability exists, but matrix permeability is low (less than 10 md). The average solution-gas/oil ratio (GOR) for the field is approximately 20 std m3/m3, with an increase in the field GOR after 20 years' depletion of only 35%. The main challenges experienced during drilling and production included chalk and solids production, well failures and stability problems, fracture closure during depletion, and a subsiding seafloor around the original production platform.
Improved and More-Rapid History Matching With a Nonlinear Proxy and Global Optimization
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101933, "Improved and More- Rapid History Matching With a Nonlinear Proxy and Global Optimization," by A.S. Cullick, SPE, W.D. Johnson, SPE, and G. Shi, Landmark Graphics, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
Generating reservoir-simulation models that match field production data has been a long-time industry challenge. Two workflows are presented for assisting history match. One workflow minimizes the misfit between simulated and historical data with a global optimizer. Another workflow trains a comprehensive nonlinear-proxy model with a small set of numerical simulations from experimental design to reduce the number of numerical simulations.

Introduction
History matching is, by its nature, an ill-posed optimization problem with many unknown reservoir parameters that could be adjusted to achieve a match against a relatively small amount of measured data at wells. The most common method of history match is to execute many simulations one at a time, changing a few parameters in a trial-and-error fashion. Often, a reservoir-simulation history match might require months of effort and many simulations to achieve a single model that neglects model nonuniqueness and often may not be a good predictor of future field performance.
Many automated history-match algorithms have been investigated. Early assisted history matching emphasized deterministic gradient-optimization algorithms that require complete derivatives of the production response with respect to reservoir parameters. Subsequently, the emphasis evolved to faster methods to compute the sensitivity coefficients, such as streamline simulation, with emphasis on preserving uncertainty through the integration of geostatistics. Recent developments with adjoint models have renewed interest in sensitivity-based algorithms. However, none of these methods have been taken up widely by practitioners.
With black-box optimization, the number of required simulations to achieve a match can be very large, numbered in the hundreds of simulations. If a single simulation model takes many hours to execute, there is good incentive to reduce the number of simulations for the optimization, even with the use of a distributed-computing system.
This study used a global optimizer, while seeking to reduce the number of simulations with a fast proxy model. The use of proxy-regression models has been suggested to reduce the number of required simulations, but analytical-response models may not be sufficiently robust to represent the nonlinear reservoir production and pressure vs. time profile data. The use of neural networks as nonlinear-proxy models also has been suggested. In this paper, a history-match workflow is presented that has a robust, nonlinear neural-network proxy model to improve a history match and reduce the number of finite-difference simulations required.
Techbits: Recent Horizontal, Multilateral Well Trends Examined in Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
More than 85 attendees converged on Merida, Mexico during 27–28 February for SPE's Applied Technology Workshop (ATW) titled "Horizontal and Multilateral Wells." The international audience of operators, service-company representatives, and academics explored the multidisciplinary nature of developing and managing these wells and the ways to maximize their design, drilling, and completions processes. Over eight sessions, the workshop covered a range of topics, including an overview of the technology; geology and geoscience concerns; reservoir performance and modeling; understanding the wellbore and its effect; drilling, completion, and stimulation practices; economic and risk analysis of the technology; and future challenges.
ATW Cochairpersons Benito Ortiz of Pemex E&P and Ding Zhu of Texas A&M University chaired the first session, which focused on the current state of the art in horizontal and multilateral wells planning. Ortiz gave the opening presentation, reviewing his company's approach to horizontal and multilateral technologies. His overview addressed the importance of horizontals and multilaterals to Pemex and to the industry as a whole. Ortiz stated that "the easy oil in Mexico is over," which is the driving force for the application of the new technology. He emphasized that horizontal and multilateral wells employ multidiscipline-oriented technologies, and that successful implementation will require communication and mutual understanding between each member of the project.
Chevron's Julie Bonner presented a revealing summary about the history and status of worldwide multilateral well applications. Bonner stated that high oil prices coupled with reserves availability and accessibility challenges have accelerated the implementation of horizontals and multilaterals. The efficiency and profitability of many of the technologies developed for these wells strongly depend on reservoir characteristics, and Bonner emphasized that people, planning, and proper implementation are key issues in the development of the required technology.
Bonner also chairs the Technical Advancement of Multilaterals (TAML) committee, which set up a classification system for multilateral wells based on the amount and type of structural support provided at the junction of a multilateral. The TAML Level-3 junction, in which the main bore is cased and cemented and the lateral bore is cased but not cemented, is the junction of choice in the industry because of its flexibility for both new and existing well applications, its openhole support, and its ability to support multiple laterals.
Technology Insertion: Pure Play or Witches' Brew?
Authors: Holland Dutch , Skarke Gary 
Published: February 2015

Management
It has been said that running a business is easy; all you have to do is buy some stuff, sell some stuff … and that is all there is to it … except for a few million details. It might also be said that inserting new technology is simple; all you have to do is buy/build some software and then implement it … and that is all there is to it, except for a few million details.
Tongue in cheek? Of course, but there is nothing tongue in cheek about inserting new digital energy technology into upstream assets while production is running flat out. While much of the technology holds great promise, the difficulty in implementation is much more complex and difficult than imagined.
Technology can be a real problem solver only if two conditions are met: the technology must work and it must be successfully implemented in upstream business units. During the rollout, the workable technology system must be made ready for users, and users must be made ready to use the new technology. Simple? Not really. Industrywide, many technology insertions continue to be highly problematic, producing disastrous results.
Why? Primarily it is that one "deadly" word that inevitably breeds widespread confusion: implementation. The truth is that there are two legitimate, but very different, ways of getting new technology into play—deployment and adoption. Both ways require different actions and generate different reactions and results. Consequently, when people are not clear whether implementation means deploying or adopting a particular technology, be prepared for a technology insertion failure.
Consider how these pure, very different, very technical rollout strategies are defined. When management decides a technology will be good for the company and mandates that all units use it for business operations by a specific date, that is a "deployment" or taking an action requiring others to respond. Imagine the chief of operations of an airline saying to pilots that the new engine-start procedure is to be used for all engine starts beginning Monday morning at 0800 hours. That is a deployment.
Technology Focus: Deepwater Exploration and Production (June 2008)
Authors: Olson Karen 
Published: February 2015

Technology Focus
The technical challenges of deepwater development cross all disciplines and all phases of a deepwater field's life. It starts with the explorers, who interpret subsalt images to locate potential fields hidden below thousands of feet of salt at depths reaching the current limits of our rigs. It continues with the drillers, who are drilling faster and deeper and collecting critical data to help subsurface engineers appraise the size of the field. Additionally, they provide a stable wellbore that enables the completion engineer to complete the well with little-to-no formation damage and possibly stimulate the formation with reliable downhole equipment. Finally, subsea and facility experts step in and install subsea and surface kits (depending on whether the completion is wet, dry, or hybrid) designed to handle a range of the field's conditions.
Long-term production from deepwater fields has been a challenge and will become even more challenging with respect to being able to produce wells at high rates initially and recover the maximum reserves. Producing beyond primary depletion will require the use of artificial lift (e.g., gas lift or electrical submersible pumps in the well or at the mudline) and reservoir-pressure maintenance (either natural or artificial) and, possibly, enhanced oil recovery.
As we continue to explore in deep water, new horizons at depths never before completed are demanding development of new ideas and new technologies. As professionals working in the oil industry, we need to continue working together to come up with new ways to develop these deeper high-pressure reservoirs; we need to keep that "can-do" attitude.
Deepwater Exploration and Production additional reading available at the SPE eLibrary: www.spe.org
SPE 110089 • "Calibrating the Mechanical Properties and In-Situ Stresses Using Acoustic Radial Profiles" by Colin M. Sayers, SPE, Schlumberger, et al.
IPTC 11282 • "Planning a Deepwater Well for All Seasons: Platina-2, a Combined Appraisal/Development Well" by Ian Brown, BP plc, et al.
SPE 112472 • "Meeting the Flow-Assurance Challenges of Deepwater Developments: From Capex Development to Field Startup" by M.M. Jordan, SPE, Nalco, et al.
SPE 111629 • "Techniques for Monitoring the Recovery of Deep, Cold-Water Habitats Following Physical Disturbance From Drilling Discharges" by Daniel O.B. Jones, National Oceanography Centre, et al.
Subsea Gas Lift in Deepwater Applications
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18820, "The Use of Subsea Gas Lift in Deepwater Applications," by Subash S. Jayawardena, George J. Zabaras, SPE, and Leonid A. Dykhno, Shell Global Solutions, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
Riser-base gas lift is used in subsea developments for production enhancement. It is an effective method to suppress severe slugging that occurs in flowlines with downhill inclination. In some cases, gas lift can aid blow-down for hydrate prevention. Gas lift is not always needed because its effectiveness depends on reservoir performance, fluid properties, seabed terrain, subsea architecture, and flowline and riser specifications. The need for gas lift, optimal operability, and system design should be assessed from various aspects, including flow assurance. A generic set of guidelines was developed on the basis of past experience with riser gas lift applications for different deepwater subsea projects and associated multiphase-flow phenomena.

Introduction
This paper discusses riser-base gas lift for deepwater subsea oil-production systems. The focus is how flow-assurance concerns affect various engineering decisions in designing a gas lift system. Riser-base gas lift is injection of a predetermined rate of gas from the host facility into the production flow-line (riser) at the seafloor. The reasons for gas lifting can vary, but the most important pertain to flow assurance, production enhancement, flow stabilization, and flowline depressurization.

Why Gas Lift Is Needed
The stages of a field's life should be studied to determine when to install and operate the gas lift system. Gas lift is not always beneficial; in some cases, increasing the gas rate may be detrimental to the performance of the subsea system.

Production Enhancement.
Gas lift for production enhancement lowers the flowline pressure. Typically, gas lift is needed with high water cuts in the flowlines, low-GOR fluids, and low-to-moderate production rates. The effectiveness is higher in systems with low production-system-inlet pressures. One major advantage of gas lift for production enhancement is that there are no moving parts in the subsea system, apart from valves and chokes. Compression for gas export is almost inevitable in any subsea development; therefore, the supply of lift gas during production is not a major issue.
When to use gas lift for production enhancement should be determined by use of integrated (reservoir/wells/flowline) production modeling. The study also should include the water/gas injection to the reservoirs. Accuracy of flowline/riser pressure-drop and liquid-holdup calculations in multiphase-flow models and the accuracy of pressure/volume/temperature predictions are crucial. This accuracy becomes more important in larger-diameter flowlines with deepwater risers in which the multiphase behavior is different from that in smaller-diameter systems.