bluuebunny/crossref_metadata_2025 huggingface dataset:
Overview: Health, Safety and Environment (July 2005)
Authors: Veil John
Published: February 2015

It is a real challenge to summarize the three disciplines of health, safety, and environment (HSE) in just half a page. All three have important roles in the petroleum world, yet they are vastly different. Specialists in one discipline may know little about the other disciplines. Unlike most other JPT topics, regulatory issues contribute significantly to management of HSE.

In March, professionals from many countries gathered in Galveston, Texas, for the biennial SPE/EPA/DOE Exploration and Production Environmental Conference. Most of the papers featured here, along with numerous other interesting papers, were presented at that meeting. This year, the conference included additional discussion on safety and security.

The process of finding and producing oil and gas and bringing products to market produces many effects on the air, water, and land, as well as on plants, humans, and animals. The industry has made great strides in the past few decades through technology development and pressures from governments. Yet the public does not perceive this industry as being a “clean” industry; we have a long way to go to improve both reality and perception. Regulatory initiatives and public pressure will force new developments in managing drilling wastes, produced water, and air emissions, among other industry byproducts.

The oil and gas industry has opportunities to use its vast skills and impressive technological capabilities to help society meet other health and environmental needs. Two examples that readily come to mind are injection of carbon dioxide for enhanced recovery or for permanent sequestration and treatment of produced water for beneficial reuse in arid areas.

Finally, we must remember that the men and women in this industry frequently work in extreme environments and with complicated and potentially dangerous equipment. Accident rates and fatalities continue to be higher for the E&P sector than for other heavy-industry sectors. It is critical to improve the safety of oil and gas operations to protect our work force. Many challenges remain in HSE.

Available from the SPE eLibrary: www.spe.org

SPE 94476 - “Cost-Effective Treatment of Barium from Coalbed-Natural-Gas Produced Water,” by J.T. Cline, SPE, Anadarko Petroleum Co.

SPE 93796 - “Environmental Regulatory Framework in Europe: An Update,” by E. Garland, SPE, Total

SPE 88673 - “Comprehensive Solutions to Drilling-Waste Management,” by Abdullah Al-Suwaidi, ADCO, et al.

SPE 94371 - “Increased Access to Federal Lands Through Data Sharing,” by S.D. Belieu, SPE, Nebraska Oil and Gas Conservation Commission, et al.

SPE 94177 - “Potential Nontraditional Uses of Byproduct E&P Produced Sulfur in Kazakhstan,” by P.W. Beall, Battelle Memorial Inst., et al.
Seabed Effects of Synthetic-Based-Drilling-Mud Cuttings in the Gulf of Mexico
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94086, "An Assessment of Seabed Impacts of Synthetic-Based-Drilling-Mud Cuttings in the Gulf of Mexico," by J.M. Neff, SPE, Battelle; A.D. Hart, Continental Shelf Assocs. Inc.; J.P. Ray, SPE, Oceanic Environmental Solutions LLC; J.M. Limia, SPE, Baker Hughes Drilling Fluids; and T.W. Purcell, American Petroleum Inst., prepared for the 2005 SPE/EPA/DOE Exploration and Production Environmental Conference, Galveston, Texas, 7-9 March.

The U.S. Gulf of Mexico (GOM) Comprehensive Synthetic-Based-Muds (SBMs) Monitoring Program used a combination of physical, chemical, and biological measurements to survey 14 drillsites on the continental shelf and continental slope of the GOM where cuttings generated while drilling with SBMs had been discharged. Three continental shelf and three continental slope sites were selected for more intensive investigation. The objective was to document the distribution of cuttings in drillsite sediments and to characterize the areal and temporal extent of chemical and biological changes resulting from cuttings discharges.

Introduction

The largest volume of waste generated during drilling is drilling mud and drill cuttings. There are three basic types of drilling muds: water-based mud (WBM), oil-based mud (OBM), and SBM. Most wells in U.S. waters have been drilled with WBM. WBM and associated cuttings usually are permitted for discharge in federal waters. OBM offers several technical advantages over WBM for difficult drilling operations; however, OBM and OBM cuttings have never been permitted for ocean discharge in U.S. waters.

The need to drill increasingly difficult deepwater and deviated wells, coupled with the economic and safety advantages of ocean discharge of cuttings, has led to development of SBM. SBM is designed to be less toxic and to biodegrade in marine sediments faster than OBM, while providing the technical advantages of OBM when drilling difficult wells. The U.S. Environmental Protection Agency (EPA) defines SBM as drilling mud in which a synthetic-based-fluid (SBF) chemical is the continuous phase with water as the dispersed phase.
Guest Editorial: The Role of a Consultant - What Is It Really?
Authors: Ellul Ivor
Published: February 2015

The title of the article might cause one to pause momentarily since I am sure that we all know what a consultant is and what his associated role should be. I am equally sure that if one were to ask a group of consultants the same question, the answers would be interestingly varied. As an engineer, consultant, and ultimately, a business owner, I take this opportunity to distill more than 25 years of experience that I have used to build a leading consulting organization, while sharing some of the more controversial issues that arise.

Dictionaries proclaim that a consultant is an expert who gives advice. Additionally, it is believed that the word consultant has been used for some time, since before 1892. So, what is it that has driven the need for this "species" from as far back as the 19th century? The answer is simple and partly has to do with the expertise factor, but, above all, it has to do with the time/money factor. A client employs a consultant to get something done more quickly (and, one hopes, better) than he could have done it himself given his lack of available and qualified resources. As a result, the job should cost less. In addition, the value added must always be significantly greater than the value paid out.

Consultants are prevalent in a number of industries including medical, aerospace, transport, and construction. The energy industry is no different, and one comes across a wide spectrum of, on the one hand, independent consultants and, on the other, larger organizations geared to take on and execute large projects. Wherever you are in the spectrum, there are a number of fundamental prerequisites that define a true consultant. These include the following:

Expertise. This comprises the technical and, possibly, commercial background necessary to address the problems at hand and deliver a successful solution.

Experience. Armed with the technical knowhow, this relates to the fact that the individual or company has successfully executed the type of work currently under consideration.

Deliverability. No matter how smart and how experienced one is, if one cannot deliver on time, on budget, and to the client's satisfaction, then it is all for naught, and the client's time and money have been wasted.

Integrity. This is a key element in today's business environment and hinges on one doing what one says one is going to do while ensuring that there are no conflicts of interest along the way. This is especially important given the fact that a consultant is usually exposed to sensitive client data that must not be seen by any third party. Sanctity of contracts is key, whether constituted on the basis of a handshake or resulting from a 20-page document.
Overview: Well Stimulation (July 2006)
Authors: Dusterhoft Ron
Published: February 2015

As I write this, my third and final opportunity to select technical papers for this feature, I find myself in Baku, Azerbaijan, the birthplace of our modern-day petroleum industry. This is an amazing place, where the history of our industry collides with the present. It is still possible to see some of the earliest commercial oil wells that were dug by hand and cased with wood; while just offshore, huge new development projects use some of the most modern technology available to the industry.

Even with current prices for oil and gas, our industry struggles to supply the energy to support the dynamic economies of the world today. Achieving the goal of long-term, low-cost sources of hydrocarbons will require significant technology advances in the area of well stimulation. From the papers I have seen this year, it is apparent that these technological advances will affect many different portions of our industry, from old, mature fields, where significant reserves have previously been economically unattractive, to the new, major ultradeepwater projects that are being evaluated today. The challenge will be to increase productivity, and then to maintain that increased productivity throughout the life of the field to provide improved ultimate recovery.

New and innovative stimulation technologies are emerging that will shake the foundations of some of our tried and proven methods. Still, in other cases, we see elegant enhancements to improve the performance of existing technologies. It appears that the future challenge will be for us to find more-cost-effective ways to improve well productivity.

It appears that well stimulation will remain a dynamic part of our industry. I am hopeful that this industry will continue to be attractive to new, innovative, and challenging minds who will continue to shape the future of the petroleum industry.

Well Stimulation additional reading available at the SPE eLibrary: www.spe.org

SPE 98329 "Evaluation of Nonlinear Fracture Relative Permeabilities and Their Impact on Waterfrac Performance in Tight Gas Sands" by R.B. Sullivan, SPE, Anadarko Petroleum Corp., et al.

SPE 98314 "A Breakthrough Fluid Technology in Stimulation of Sandstone Reservoirs" by F.E. Tuedor, SPE, Schlumberger, et al.

SPE 97659 "Controlling Formation Fines at Their Sources To Maintain Well Productivity" by P.D. Nguyen, Halliburton, et al.

SPE 97161 "Proppant Flowback Prevention—A New Technology for Low-BHST Applications" by D.E. Johnson, SPE, Hexion Specialty Chemicals Inc., et al.
Continuous Improvements in Acid Fracturing at Lake Maracaibo
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96531, "Acid Fracturing in Lake Maracaibo: How Continuous Improvements Kept on Raising the Expectation Bar," by B. Burgos, Shell Venezuela S.A.; M. Buijse, SPE, Shell Intl. E&P; E. Fonseca, Shell Venezuela S.A.; and A. Milne, M. Brady, SPE, and R. Olvera, Schlumberger, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9-12 October.

The Maraca limestone formation is a part of the Cogollo carbonate group below Lake Maracaibo, Venezuela. Acid fracturing with an organic-acid system has proved to be a pivotal completion strategy for achieving higher productivities and increasing reserves. The main challenges are the relatively high hydrogen sulfide (H2S) content, 280°F reservoir temperature, the asphaltenic nature of the crude, and the long completion tubing that limits pump rate.

Introduction

The Maraca limestone formation is a 20- to 30-ft upper member of the Cogollo carbonate group at 15,000 to 16,000 ft in the Urdaneta West field below Lake Maracaibo, Venezuela. Reservoir volumes and productivity are attributed mainly to matrix development, in contrast with the rest of the Cogollo, where natural fractures play a major role in well production.

When stimulation and development strategy began focusing on the Maraca group, a number of matrix stimulations were performed, most using coiled tubing (CT) at low pumping rates and volumes. The first few treatments used 15% hyrodochloric acid (HCl), but the acid system was switched quickly to an organic acid blend (13% acetic and 9% formic) because of the high reactivity of the HCl and its tendency to form sludge after contacting the asphaltenic Maraca oil. These matrix treatments had modest results, and the gained productivity was lost after a few months of production.

Acid Fracturing With Organic Acid

Acid fracturing was considered as an alternative to stimulate Maraca wells. Not only would acid fracturing increase well productivity, but it also would help retain the generated conductivity for a longer time period. Acid fracturing is a stimulation technique where acid, usually HCl, is injected into the reservoir at fracturing pressures. As the acid flows along the fracture, the fracture face is dissolved in a nonuniform manner, creating conductive or etched channels that remain open when the fracture closes. The effective fracture length is a function of the type of acid used, the acid reaction rate, and the fluid loss from the fracture into the formation.

Acid fracturing was preferred to hydraulic fracturing because proppant cleanout in a sour well with CT required operational and safety resources not yet in place. Additionally, the high conductivity of an acid-etched fracture made acid fracturing a more attractive technique if comparable fracture lengths could be achieved.
Achieving True Reservoir Stimulation in Deepwater Horizontal Sandstone Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95826, "Achieving True Sandstone-Reservoir Stimulation in Deepwater Horizontal Wells," by A. Mendez, SPE, BJ Services Co.; L.F. Neumann, SPE, and E. de Almeida Pinto, Petrobras; and R. Torres, SPE, R. Farias, SPE, and M. Acosta, SPE, BJ Services Co., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.

In offshore horizontally completed sandstone wells, an acid job usually is pumped to remove filter cake. When these wells are acidized with a hydrochloric (HCl)/hydrofluoric (HF) acid mixture, the resulting skin values usually are positive. An improved HF acid system (IHF) was introduced that uses an organophosphonic acid complex to control HF generation and to reduce potentially damaging secondary and tertiary precipitates. The full-length paper describes the results and case histories of field treatments that resulted in truly stimulated wells with negative skin.

Introduction

Production began in the Campos basin offshore Brazil in the early 1970s. Since then, more than 40 oil fields have been found in water depths between 260 and 7,800 ft. The most-prolific reservoirs are late Albian to early Miocene siliciclastic turbidites. These reservoirs are developed with horizontal and high-angle wells drilled into poorly consolidated reservoirs. The deepwater subsea wells must be designed to allow high production rates, typically more than 10,000 to 15,000 BOPD, with lifetime completions to avoid costly interventions.

Campos basin reservoirs were responsible for approximately 1.2 million BOPD in 2002, almost 83% of total Brazilian production, and are expected to produce 1.6 million BOPD by the end of 2005.

Sand control is required for wells in sandstone reservoirs that are poorly sorted medium-to-fine sands. These wells need to be completed with a package that includes premium screens in the horizontal section. To pump the gravel throughout the horizontal section effectively, a fluid composed of xanthan gum and calcium carbonate is used to create a filter cake and leave the formation stable.

Injector wells are completed in the same way as producers except an acid treatment is required to remove the filter cake and drilling residues remaining in the very-near-wellbore vicinity. Most injector wells are treated with the common HCl/HF mixtures.

Laboratory core flow tests were performed with core plugs from two different fields in the Campos basin. Tests compared results of treatments with several different acid blends. Results demonstrated that the IHF is capable not only of removing the filter cake but also of stimulating the formation more than the regular HF acid mixture (RHF). After laboratory tests were concluded, the IHF was field tested in two wells with a stimulation tool run with the gravel-pack tool in a single trip.
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 (>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 (<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.
Technology Focus: Artificial Lift (July 2008)
Authors: Scott Stuart L.
Published: February 2015

Technology Focus

Artificial lift plays a fundamental role in several international plays. This month, artificial lift in oil-sand and deepwater developments is highlighted. In both cases, artificial lift is not just accelerating production but is vital to the economic success of the overall development.

Today, the Canadian oil-sand developments have followed these different approaches: mining, cyclic steam injection, and steam-assisted gravity drainage (SAGD). As reservoir depth increases, artificial lift, rather than mining, is used to bring hydrocarbons to the surface. While cyclic steam injection and SAGD both push the high-temperature envelope for pumping, new techniques are being proved for this harsh environment. During the production phase of cyclic steam injection, the wells initially flow to the surface. Later production moves into the "flumping" stage (simultaneous flowing and pumping) and then into pumping. While sucker-rod pumping has been dominant, progressing-cavity pumps and electrical submersible pumps (ESPs) are being proved under these extreme conditions. In addition to downhole pumping, there is widespread use of surface multiphase pumps. Technologies that allow pumping high-temperature fluids without cooling represent opportunities to retain heat and improve the overall process efficiency. Surface pumping of a high-temperature multiphase mixture has become an established technology in Alberta.

For deep water, artificial lift plays a strategic role, enabling companies that possess advanced technology to develop fields that other companies may determine to be too difficult. The ability to deliver an advanced artificial-lift system is the difference between booking reserves and walking away from deepwater discoveries. Only recently have we seen rapid growth in the application of subsea multiphase pumping. In addition to seafloor boosting, several other artificial-lift methods are applied in deep water, including gas lift and wellbore ESPs. In all cases, the ultimate success of these developments depends on the reliability of the artificial-lift system combined with the cost of intervention.

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

SPE 113904 • "Recent Advances and Practical Applications of Integrated Production Modeling at Jack Asset in Deepwater Gulf of Mexico" by Umut Ozdogan, Chevron Energy Technology Company, et al.

IPTC 11594 • "A New Approach to Gas Lift Optimization Using an Integrated Asset Model" by Fernando Gutierrez, Schlumberger, et al.

SPE 110234 • "Overview of Beam-Pump Operations" by O. Lynn Rowlan, Echometer Company, et al.

Additional reading available at OnePetro: www.onepetro.org

OTC 18820 • "The Use of Subsea Gas Lift in Deepwater Applications" by Subash S. Jayawardena, Shell Global Solutions, et al. (See JPT June, 2008, page 64.)
First Metal-PCP SAGD Field Test Shows Promise for Heavy-Oil Hot Production
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110479," World's First Metal-PCP SAGD Field Test Shows Promising Artificial-Lift Technology for Heavy-Oil Hot Production: Joslyn Field Case" by Jean-Louis Beauquin, SPE, and Felix Ndinemenu, SPE, Total E&P; Gilles Chalier, Total E&P Canada; Lionel Lemay and Laurent Seince, PCM; and Alex Damnjanovic, KUDU Industries, originally prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed.

Finding a reliable artificial-lift (AL) pumping system for heavy-oil thermal recovery has been a challenge, mainly because of the high operating temperatures (greater than 150ºC). Available options such as rod pumps and electrical submersible pumps (ESPs), which are well proved in the industry, are not well suited for thermal production. While rod pumps offer high-temperature service, they are limited in the flow rate they can deliver. ESPs can handle high volumes of low-viscosity fluids but are still limited in terms of maximum operating temperature. Metal progressing-cavity-pump (PCP) technology has been developed to meet the high-temperature requirement of steam-assisted gravity drainage (SAGD) and other thermal-recovery processes.

Introduction

Recovery of the world's large reserves of extraheavy oil (found mainly in the oil sands of Canada and Venezuela) by thermal processes has been increasing because of the high price of oil. Key to this recovery process is AL, which is required because of the very high density and viscosity of the crude and the relatively low reservoir pressures. Although gas lift remains an AL option when high pressure gas is available, pumping techniques are more popular because of their relatively higher efficiency and ability to generate more pressure at the surface for delivery to the treating plant. However, the main challenge with hot pumping is the high temperatures often required [as much as 260°C for SAGD and 350°C for cyclic steam stimulation (CSS)].

The dominant pumping technologies available are beam/jack pumps, ESPs, and elastomer PCPs. All these pumps have their peculiar limitations for hot production. While beam pumps offer high-temperature service, they are limited in the flow rate they can deliver. ESPs can handle high volumes of low-viscosity fluids, but they are still limited in terms of maximum operating temperature. For PCPs, the limitation is operating temperature of the elastomer (maximum 150°C).
Getting the Last Gasp: Deliquification of Challenging Gas Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11651, "Getting the Last Gasp: Deliquification of Challenging Gas Wells," by A.V. Bondurant, SPE, B.D. Dotson, SPE, and P.O. Oyewole, SPE, BP plc, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4–6 December. The paper has not been peer reviewed.

A common characteristic of "challenging" unconventional gas resources—namely, low-permeability sands, shale, and coalbed methane (CBM)—is that the ultimate recovery depends on economic removal of liquids accumulation, generally termed "deliquification." The problem affects thousands of wells, and the solution involves not only technology development but also knowledge management and building resource capability. Industry is working on a variety of deliquification technologies for challenging gas, with developments ranging from adapting existing oilfield technologies to developing gas-specific technologies to developing "on the horizon" technologies. Examples in each stage of development are presented.

Introduction

A distinguishing characteristic of North American land-based gas production is the large number of low-rate wells. In the continental US, the majority of gas wells produce less than 100 Mscf/D. The low rates reflect the maturity of North American gas production and the predominance of challenging production from low-permeability-sand (<0.1 md), shale, and CBM reservoirs.

Low-rate gas wells almost always cease production because of liquid accumulation in the wellbore. Consequently, deliquification is of great importance. From a worldwide perspective, the current need for deliquification of low-rate wells is more modest. As production from high-rate wells declines, similar technical and economic challenges will be faced outside North America and will benefit from the solutions developed there.

For this study, a gas well is any well making 50 bbl/MMscf or less of stock-tank hydrocarbon liquids. An actively producing well is one having production reported in the second half of 2005. Production data from several eastern states, which tend to have very-low-rate gas wells, were not readily available and, therefore, were not included in this analysis. With these definitions, data were collected on 235,000 active producing gas wells in the major producing states for the second half of 2005.

Approximately 150,000 wells that produce less than 100 Mscf/D/well pro-duce approximately 7.5 Bcf/D collectively, 10% of the North American gas consumption. Most of these wells either are impaired by liquid accumulation or are producing with some form of artificial lift for deliquification. Deliquification in North America involves a very large well count, with generally a small incremental effect on each well.