bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: Multilateral/Extended Reach (July 2006)
Authors: Mason Colin 
Published: February 2015

Cost-effective access to remote offshore reserves from fixed platforms or to offshore reserves that exist close to onshore locations often requires the use of extended-reach drilling (ERD) and multilateral technology. The ability to apply this technology routinely in future oil provinces, such as those in remote Arctic locations, will be vital to ensure economic success.
A recent class of wells, termed ultra-ERD, has highlighted technical challenges that require both the nurturing and advancement of technology. Note that an ultra-ERD well can be loosely defined as one that has significantly higher step-out than other wells in the same reservoir horizon. The feasibility of drilling and completing such wells is primarily determined by stepout, vertical depth, and degree of difficulty imposed by the subsurface environment. Currently, the industry is looking to drill its first 12-km-stepout ultra-ERD well.
Current technology development is targeted at increasing reliability of downhole tools, evolving novel methods of reducing equivalent circulating density, and honing techniques that deliver effective and quantifiable torque and drag reduction. One key obstacle is that of reliably proving up prototype technology before its application in the field. In many cases, through necessity, only laboratory tests or limited field trials have been carried out.
Designs for ultra-ERD wells also pose an interesting challenge. One key to success is to identify the most critical operations correctly and build the well design around those operations. In this context, one particular mindset that must be overcome is that of being constrained by standard casing sizes; instead, design the well to be fit for its intended purpose. However, this requirement must be tested against the challenge of long lead times for nonstandard steel products and the likely constraint of having to work with a nonoptimal rig.
While incremental improvements in drilling hardware are undoubtedly occurring, there are clear opportunities for performance gains through real-time analysis, monitoring, diagnostics, and visualization of drilling and casing/completion-running operations. This initiative will require a joint effort by both operators and service providers to identify and meet industry needs.
Multilateral/Extended Reach additional reading available at the SPE eLibrary: www.spe.org
SPE 98471 "Introduction of New Drilling Technology Improves Performance of Mature North Sea Assets" by J. Anderson, Talisman U.K. Ltd., et al.
SPE 95652 "Two-Phase Correlation for Multilateral-Well Deliverability" by R. Kamkom, Texas A&M U., et al.
SPE 97520 "Redevelopment of Matured Multilayered Carbonate Offshore Field Through High-Technology Horizontal and Multilateral Wells" by R. Kumar, SPE, Oil & Natural Gas Corp. Ltd., et al.
Enhanced Landfarm Performance Through the Use of Saline Water and Weekly Tilling
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98568, "Significantly Enhanced Landfarm Performance Through the Use of Saline Water and Weekly Tilling," by A. Al-Mahruki, R. Al-Mueini, and Y. Al-Mahrooqi, Sultan Qaboos U.; A. Al-Sabahi, Petroleum Development Oman; G.H.P. Roos, The Petroleum Inst.; and H. Patzelt, Sultan Qaboos U., prepared for the 2006 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Abu Dhabi, UAE, 2-4 April.
An experimental landfarm for the bio-remediation of petroleum hydrocarbon was constructed on the Fahud concession. From March to June 2005, the hydrocarbon content of the soil in the saline beds had fallen below 2%, while the control areas still contained more than 4%.

Introduction
Landfarming is an established process to reduce the petroleum content of contaminated soil through stimulated microbial degradation. The process is simple to design and operate, and it is relatively cost-effective. In southern Arabia, where large areas of land are available, the major remaining drawbacks are the long operating times of up to 2 years and the high water consumption of the process. The second problem is especially severe when fresh water is in short supply and must be transported over a long distance or must be produced by desalination on site.
In the arid saline environments of the Arabian peninsula, the use of cheaper, brackish water for landfarming would be highly desirable, both for economic and ecological reasons. Such water had not been used previously because of the assumption that the microbial activity, and the associated biodegradation rate, decreases dramatically with rising salinity. This assumption was attributed to seemingly unfavorable physical properties of saline and hypersaline environments (&gt;15% salt), such as the high dielectric constant, low free-water activity, low oxygen solubility, and, frequently, complete desiccation.
However, successful demonstrations of xenobiotics degradation under hypersaline conditions have shown otherwise. It was shown, for instance, that by converting a former produced-water pit into an open-air bioreactor, bioremediation of even weathered hydrocarbon is possible in salt-saturated water.
This study investigated an experimental landfarm, comparing hydrocarbon degradation and biological activity between beds that were irrigated with water of different salinities. The overall aim was to improve the existing landfarm operations in Oman and, as an added ecological asset, to reduce freshwater consumption at the remote Omani oil fields.

Experimental Landfarm
The Fahud concession is in the north-western part of the Sultanate of Oman, in an arid gravel desert approximately 250 km west of Muscat. As shown in Fig. 1, seven identical beds measuring 25×5 m, with a height of approximately 50 cm, were laid using fresh drilling mud, which had been diluted with sand to a total hydrocarbon concentration of 5.1 wt%.
Horizontal-Openhole Gravel-Packing Operations in the Campos Basin
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 106364, "The 200th Horizontal-Openhole Gravel-Packing Operation in Campos Basin: A Milestone in the History of Petrobras Completion Practices in Ultradeep Waters," by L.C.C. Marques, SPE, L.C.A. Paixao, V.P. Barbosa, M.O. Martins, A. Calderon, SPE, C.A. Pedroso, SPE, L.H.C. Fernandes, J.A. Melo, C.M. Chagas, and N.J. Denadai, Petrobras, prepared for the 2007 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 30 May-1 June.
The full-length paper presents an overview of the evolution of openhole gravel-packing practices and experience after 200 wells have been completed successfully with this technique in the Campos basin. A comprehensive description of the main steps taken to improve horizontal-openhole gravel-packing (HOHGP) practices in unconsolidated oil-bearing turbidites is presented. Since the first HOHGP job in 1988, completions have moved progressively from shallow- to ultradeepwater scenarios. Along this path, a series of innovations has been incorporated into the sand-face-completion practices.

Introduction
The most prolific reservoirs in the Campos basin are the Upper Cretaceous and Tertiary turbidites. The high-permeability (approximately 1,000 to 8,000 md) stacked and amalgamated reservoirs are spread over shallow, deep, and ultradeep water within the basin. Dictated by the depositional model associated with turbidites, the sand uniformity of these poorly- or unconsolidated sand lenses varies significantly. The presence of reactive-shale streaks is recurrent in some of these turbidites. As in many other offshore basins in the world, the first oil discoveries (early in the 1980s) were in shallow waters. These good exploratory results propelled the move progressively from shallow to ultradeep water. However, since the original oil discoveries, it has been realized that a sand-management strategy was necessary to achieve desirable production levels.
Sand control is an umbrella term comprising different approaches to dealing with sand-production problems. Sand-control methods include frac pack, chemical consolidation, screens, and gravel packing. The Petrobras philosophy is one of zero tolerance for sand production. Should there be the slightest chance of sand production, a sand-control method is installed in wells. This preventative approach stems from wellbore-integrity concerns, prohibitively high well-intervention costs, the need to maximize production rates, safety concerns, and the inability of topside equipment to handle sand.
Gravel packing is considered the best alternative for sand control in horizontal-openhole wells with good vertical permeability, nonuniform sands, and no lamination. In addition, filling the screen/wellbore annulus of an openhole horizontal well with properly sized gravel creates a secondary barrier to the migrating sand grains, thus increasing the longevity of the gravel-pack screens.
Extended Reach: New-Generation Frontier Drilling Rigs
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19067, "Extended Reach: New-Generation Frontier Drilling Rigs," by F.J. Husband, SPE, George Bitar, SPE, and Mark Quinlan, SPE, Parker Drilling Company, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
Common features of frontier development are fragile environment and high operating costs, which require unique operating methods. Planned well trajectories have departures and complexity such that feasibility risk is a critical part of the evaluation before investing in these projects. Primarily, this risk is determined on the basis of rig design and capacity to drill these extreme-reach well designs. Aspects of land-rig design, procedures, and operations that enable continued drilling of more-complex well trajectories with longer departures are discussed.

Early Experience
The original Prudhoe Bay multiwell development-drilling programs from small pad-based surface locations required directionally drilled well trajectories to reach the bottomhole targets. Bottomhole-assembly (BHA) technology and rig-hydraulic capacities enabled extended-reach drilling (ERD) with horizontal displacement at least twice that of vertical depth. The technique increased well productivity, limited environmental effects, and helped to avoid surface obstacles. Improved directional-drilling technology and departure limits enabled progressively smaller pad sizes. New rig designs were required to fit the rig on the site while allowing transportation access and simultaneous drilling and production activities. Elimination of pits and new cantilever designs were implemented to fit the rig between more-tightly spaced wellheads.
Approximately 10 years ago in China, reserves from the Xijiang 24-3 offshore field in the South China Sea were upgraded after a revised seismic interpretation provided several new locations. However, the bottomhole locations required departures beyond technical limits at the time. By 2006, 13 ERD multilateral wells were drilled from Platform 24-3.

One-of-a-Kind Projects
The designing, fabricating, and operating of special-purpose drilling rigs for remote environments is unique, but all such projects have common features.Challenging well designExtreme environmentDifficult delivery conditionsConstrained exit conditions
Sunkar Rig 257. This purpose-built rig was constructed on a unique shallow-draft arctic hull designed for drilling in extreme ice and wave conditions of the north Caspian Sea. It required year-round self-sufficient operations while drilling subsalt high-pressure/high-temperature sour-gas fractured formations by use of closed-circulation drilling techniques. Because of logistics, drilling environment, and operating regulations, these wells are among the most expensive in the industry, including deepwater wells. The unique design delivered significant benefits in executing the planned scope of work. However, it also restricts use of the vessel to regional programs without significant capital investment.
Techbits: Naphthenate Deposits, Emulsions Highlighted in Technology Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
Pau, France was the scene for a recent SPE Applied Technology Workshop (ATW) titled "Managing Naphthenates and Soap Emulsions." From 10–13 March 2008, more than 70 attendees discussed the flow assurance challenges that naphthenate deposition presents, as well as the current state of the art in mitigating their formation in the field.
Colin Smith, senior consultant with Maxoil Solutions and ATW Committee Member, opened the workshop with a scene-setting discussion on the fundamentals of naphthenate sludge and emulsion formation. If left unchecked, naphthenate deposits may cause fouling or plugging of production equipment such as flowlines and separators, and the formation of stable emulsions may prevent efficient oil/water separation, increasing separator residence times. The problem is more common than the industry might think, according to Smith; naphthenate deposits are present in 10% or more of North Sea crudes, while 30% of southeast Asian crudes and 20% of west African crudes demonstrate soap emulsion or sludge problems. Smith mentioned that naphthenates were first clearly identified in oilfields in the 1960s, but research and development (R&D) efforts began in earnest in the mid-1990s.
The first session of the workshop highlighted the fundamentals. Johan Sjoblom, Professor at the Norwegian University of Science and Technology (NTNU), examined the current understanding of the different types of acids in a crude oil that can lead to naphthenate formation and sludge or emulsion problems. Monoacids (those acids with one carboxyl [COOH] group) tend to stabilize emulsions and concentrate in the oil phase or sludges, while tetracids (those with four COOH groups) can stabilize oil/water emulsions and tend to react with metallic ions such as calcium (Ca2+) to form deposits that harden irreversibly.
Christian Hurtevent, an expert in physical chemistry and deposits with Total, discussed his company's experience with emulsion formation based on oil density and acid type. In general, Total has observed biodegradation and deposit problems in problem crudes with lower API values (&lt;30), while higher API problem crudes tend to demonstrate emulsion stability challenges. The company has used an ultrasonic scanner to evaluate emulsion phase behavior, which has suggested how various naphthenic salts aggregate in a crude oil/water mixture.
Ingemar Uneback, Application Development Manager for Akzo Nobel, proposed how derivatives of naphthenic mono acids could be extracted from crude oil and used as favorable starting blocks in chemical synthesis. In the formation of surfactants, for example, several monoacids demonstrate excellent surface active properties, low viscosity, good oxidative stability, and favorable biodegradability for environmentally sensitive applications. Uneback stated that Akzo Nobel has begun testing naphthenic monoacids as surfactants with promising results for potential application in fuels, agrochemicals, oilfield process chemicals, and asphalts.
A Systematic Approach to Hostile Environments
Authors: Belani Ashkok , Orr Steve 
Published: February 2015

Management
It is well accepted by the scientific and engineering community that the world's energy needs will be satisfied primarily by fossil fuels for the next few decades at least. Despite remarkable growth in renewable energy technology during the past 20 years, increasing demand has kept the relative share of energy supplied by fossil fuels steady, at about 75%.
The International Energy Agency (IEA) has published a resource guide that illustrates where future energy supplies will be found and the relative threshold price that will spur exploration in those areas (Fig. 1). Among these are some very challenging environments. The higher price of oil and gas, which is actually a manifestation of the supply challenges the world faces, is spurring activity in many different fronts—among which are developing heavy and viscous oil deposits, oil and gas shales, as well as arctic and deepwater opportunities.
Traditionally, elevated temperatures were associated with deep producing horizons, or in some cases with known "hot spots" in the geothermal gradient. Today, the use of thermal recovery techniques in viscous crude recovery has increased the requirement dramatically for high temperature technology.

Today's Subsurface Environment
Temperature is just one of the many challenges facing the developers of oil and gas industry technology. It is useful to list the factors that must be considered—in the parlance of space or military terminology, these constitute the "Mission Profile."Shocks and vibrationCyclesAbsolute temperature and temperature rangeAbsolute pressure and differential pressureReliabilityBandwidthControlDuration of operationsCompressive, shear, and tensile strengthFlow rate
The combination of some or all of these profiles creates myriad parameter linkages that describe the operating range of equipment. As a result, standard industry classifications often are absent, confusing, or filled with caveats. What is required is an organized approach to identify and clearly state, using standard terminology, the subsurface environments of high pressure/high temperature (HP/HT). Only then will a common understanding exist across the industry; one that will result in a true quantification of the markets and the needed technology to satisfy them.
Technology Focus: Reservoir Simulation and Visualization (July 2008)
Authors: Crick Martin 
Published: February 2015

Technology Focus
The continued high price of oil is clearly feeding through to research in and application of simulation: The papers submitted for review this year contained a high proportion on recovery techniques and reservoir types that only a few years ago were of little or no interest.
Thermal-recovery methods, and especially in geologically complex reservoirs, formed a clear trend in the papers submitted. The traditional "simple" steam-flood is giving way to more-sophisticated mechanisms, such as steam-assisted gravity drainage and in-situ combustion, and both simulation and visualization can play a pivotal role in understanding what is happening in a pilot study and in planning a subsequent full-field development.
Traditionally, history matching is fundamental to simulation, and much effort has been expended over many years in attempts to automate the process. Automation not only frees up the engineer to do other things—or more commonly, to simulate more reservoirs—but also introduces a degree of objectivity into what can be a dangerously subjective process, given the highly nonunique nature of the problem. Many of the submitted papers approach the problem in a more holistic manner than earlier approaches, including the geological-modeling process within the history-matching workflow. This is a welcome trend because "history match" that violates the known geological data and conceptual model is no match at all, and its predictions should be regarded with suspicion.
Over the years, simulators have gradually improved their representation of geology—the early homogeneous boxes giving way to highly heterogeneous models with complex fault structures represented faithfully. Naturally fractured carbonate reservoirs are among the most complex geological systems encountered. From the submitted papers, as well as the oft-cited distribution of remaining oil in place worldwide, these reservoirs will come to dominate the active development projects. We all need to improve our understanding of such geology and improve our mathematical models of it.
Reservoir Simulation and Visualization additional reading available at the SPE eLibrary: www.spe.org
SPE 113918 • "Insurance Value of Intelligent-Well Technology Against Reservoir Uncertainty" by E.A. Addiego-Guevara, SPE, Imperial College, London, et al.
SPE 113917 • "The Modeling Challenge of High-Pressure Air Injection" by A.H. de Zwart, Shell, et al.
SPE 110066 • "Case Studies Illustrating the Use of Reservoir-Simulation Results in the Reserves-Estimation Process" by Dean Rietz, SPE, Ryder Scott, et al.
Clustering/Geostatistical/Evolutionary Approach for 3D Reservoir Characterization and Assisted History Matching in a Complex Carbonate Reservoir
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 113978, "Integrated Clustering/Geostatistical/Evolutionary Strategies Approach for 3D Reservoir Characterization and Assisted History Matching in a Complex Carbonate Reservoir, SACROC Unit, Permian Basin," by R. Gonzalez, SPE, K. Schepers, SPE, and S.R. Reeves, SPE, Advanced Resources International; E. Eslinger, SPE, Eric Geoscience and College of Saint Rose; and T. Back, NuTech Solutions, prepared for the 2008 SPE Improved Oil Recovery Symposium, Tulsa, 19–23 April. The paper has not been peer reviewed.
An integrated methodology combining clustering-analysis techniques, geostatistical methods, and evolutionary-strategy technologies was developed and applied to a study area of the SACROC Unit. Clustering methods were applied to well logs and core data (with high vertical resolution for many wells) to predict porosity, permeability, and rock type. Geostatistics was applied to extend the characterization into the interwell area. Evolutionary strategies were used to refine the characterization to match historical production performance.

Introduction
Initially, a two-step soft-computing procedure was developed to generate core-scale porosity and permeability profiles at well locations where no core data existed. The approach applied clustering methods, based on maximum-likelihood principles, to well-log and core data for lithology interpretation, reservoir-quality characterization, and prediction of "core" parameter profiles, with high vertical resolution for many wells. This procedure enabled populating any well location with core-scale estimates of porosity and permeability and rock types, facilitating direct application of geostatistical techniques to build 3D reservoir models. Geostatistical methods then were applied to the resulting data set, and 3D spatial models of variability for clusters, porosity, and permeability were used to generate reservoir representations of porosity and permeability for flow-simulation purposes. Finally, a computer-assisted history matching by applying evolutionary-strategy technologies was used to history match the production performance of a selected subregion in the unit.
The SACROC Unit comprises most of the Kelly-Snyder field and part of the Diamond "M" field in Scurry County, Texas. The unit is developed in Pennsylvanian-age reef carbonates of the Cisco and Canyon formations, with productive carbonates in both formations. The productive interval is composed mainly of limestone, although minor amounts of anh-drite, chert, sandstone, and shale can be found locally. Dolostone is rare to nonexistent. The overlying Wolfcamp shale constitutes a natural top and lateral seal. Toward the east and west boundaries, the Cisco/Canyon productive carbonate interval narrows and drops below the regional oil/water contact. Carbonate accumulations present extremely complex geometries and steep sides.