bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: Deepwater Developments Focus of Mumbai Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
Deepwater discoveries and development plans are expanding from well-established regions like the US Gulf of Mexico (GOM) to frontier regions such as offshore India, but there is a lag in experience that must be filled. An SPE Applied Technology Workshop (ATW) in Mumbai titled "Deepwater Development" aimed to do that, by bringing together a multidisciplinary, multinational group of 117 oilfield professionals to exchange ideas in the area of deepwater project planning and execution.
Workshop Steering Committee Chairperson N.K. Mitra of Oil and Natural Gas Corporation (ONGC) welcomed all delegates and presented an overview titled "Deepwater: An Indian E&P Perspective." He highlighted India's deepwater potential, which includes 1.35 million sq km of sedimentary area containing 10 billion bbl of reserves. He described ONGC's successful deepwater drilling effort at Sagar Samridhi in August 2003 that resulted in the discovery of the G-1, GS-15, and Vashishtha fields, which are scheduled to begin production in 2010–2012. Challenges preventing further deepwater developments in the region include drilling and completion technical hurdles, flow assurance, and a resistance to changing mind sets.
In the keynote address that followed, A.K. Balyan with ONGC saw an urgent need to increase deepwater exploration and development off the coast of India to stem its dramatically increased petroleum import bill. This will require increased cooperation among all players in the areas of reservoir management and drilling, as well as further technology optimization.
ONGC's R.S. Sharma, the chief guest of the ATW's inaugural session, pointed to nonavailability of deep- and ultradeepwater drilling rigs as driving rig costs to stratospheric levels, and estimated that each second of lapsed drilling activity at a site costs USD 146. He felt that the speed of technology development has not been keeping pace with industry needs, and placed emphasis on the areas of deepwater equipment standardization, technology for high-pressure/high-temperature (HP/HT) wells, and smart completions.

Case Histories
The first technical session reviewed two deepwater case histories. The first out-lined the planning and execution of the Shell NaKika project in the US GOM.
Integration of several new deepwater technologies from various disciplines and an integrated team of experienced people, from subsurface planning to operations, were the keys to the success of the NaKika project.
The second case study reviewed StatoilHydro's overall deepwater development and management philosophy which gives high priority to efficient inspection, maintenance, and repair. The Kristin field, with a three-stage overpressure protection design, is an example of StatoilHydro's experience with HP/HT wells.
Options are Running Out - Today's Youth Needs Convincing
Authors: Hopkins Chris 
Published: February 2015

Talent & Technology
Recently, I was part of the SPE Colloquium on Petroleum Engineering Education, an event comprising academia and industry professionals assembled to address the issue of personnel recruitment and training in the oil and gas industry. Representatives of international universities, major and independent operators, and the service and supply industry took on the challenge of answering the burning question, "How are we going to identify, recruit, hire, and train the professional employees we need for the future?"

Facing the Hard Facts
Forecasts vary, but some estimates indicate that production from existing fields will decline from current levels of around 75 million B/D to approximately 15 million B/D by 2030. To meet anticipated demand, production will need to be approximately 115 million B/D or higher. How will we fill the gap? Most will come from new exploration and development of known reserves, the remainder from enhanced-oil-recovery (EOR) techniques and unconventional sources such as heavy oil or shale oil. But getting oil from these sources will require concentration on trained people, optimized processes, and innovative technology.
Technology has kept pace through the years, allowing us to access reservoirs in more than 10,000 ft (3049 m) of water, drill extended-reach wells as far as 7.6 miles from the surface location and geosteer through thin sections of less than 10 ft (3.1 m) for more than a mile. Innovative use of technology has also helped advance industry achievements. Today, thousands of wells are equipped with monitoring systems that allow automatic 24-hour production surveillance with data transmission to a central production-management facility. This allows operators to manage by exception, focusing on problem wells instead of poring over spreadsheets of data on wells that are performing normally. New automated workflows provide operators with actionable information instead of raw data taking seismic all the way to simulation. These workflows can condense geological interpretation time from 3 years to 6 months (Fig. 1).
Although technology and workflow processes are providing the leverage to accomplish some of the demand, these two alone are not strong enough to support the industry. We must have well-trained people.

The Obstacles
Based on a benchmark survey conducted by Schlumberger Business Consulting (SBC) of 30 companies, the long feared "big crew change" is upon us and we are not recruiting the numbers to meet this need. At the present time, we are meeting demand with 40% of the geology and geophysics graduates entering the oil and gas industry (Fig. 2). But to meet the future demand, SBC has estimated that 80% of students would have to go into petroleum geology. Currently students are going into mining, hydrology, or environmental work. Many graduates in geophysics study earthquakes, volcanoes, or get into soil and rock mechanics for the construction industry.
Technology Focus: Hydraulic Fracturing (March 2009)
Authors: Chipperfield Simon 
Published: February 2015

Technology Focus
"Besides black art, there is only automation and mechanization."—Federico Garcia Lorca, Spanish poet and playwright (1898–1936)
On this basis, fracture stimulation sits firmly in the realm of mysticism, crystal balls, and tarot.
The reason for this is that unlike automation (e.g., car manufacturing) we still are uncertain of what makes fracture stimulation "work" (i.e., the critical components) and of how we evaluate and improve performance (i.e., of what constitutes a "vehicle service").
The car industry understands the components that make a car operate because each is built meticulously and repetitively. The key components that drive fracture stimulation are more difficult to determine because the process is subject to a high degree of variability in subsurface conditions. And what adds more "smoke and mirrors" to stimulation design is that much of the research that forms our basic understanding was developed more than 30 years ago on tight gas reservoirs, which bear no resemblance to the shale, coal, or unconsolidated sands stimulated today. In other words, while we have paid for a Rolls Royce we unwittingly may be driving a DeLorean.
The automotive industry assesses the performance of its cars through periodic, thorough checkups. How often do we conduct a multicomponent service on our stimulation treatments? Microseismics, continuous reservoir monitoring (by use of distributed-temperature surveys and permanent downhole gauges), and radioactive-fluid tracers are some of the technologies used to determine the "health" of stimulation treatments. Their use, however, remains the exception not the rule. Usually, expensive stimulation-treatment checkups are avoided; instead, only the oil dipstick continues to be used (i.e., pressure and rate during injection and production).
Is it not time that you better understood the key components "under the hood" and gave a complete service to your fracture-stimulation process? Only through better understanding will the "black art" be replaced by science, the performance be measured, and step changes truly be made.
Hydraulic Fracturing additional reading available at the SPE eLibrary: www.spe.org
SPE 116124 • "Case History of Sequential and Simultaneous Fracturing of the Barnett Shale In Parker County" by P.N. Mutalik, Williams Companies, et al.
SPE 118831 • "Optical-Fiber Distributed Temperature for Fracture-Stimulation Diagnostics and Well-Performance Evaluation" by Paul Huckabee, SPE, Shell E&P
SPE 119350 • "Stress Amplification and Arch Dimensions in Proppant Beds Deposited by Waterfracs" by N.R. Warpinski, SPE, Pinnacle
SPE 111431 • "New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas Production in Rockies" by K. Hughes, Chevron, et al.
Development and Use of High-Density Fracturing Fluid for Deepwater Frac Packs
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116007, "Development and Use of High-Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs," by L. Rivas, SPE, G. Navaira, SPE, and B. Bourgeois, SPE, Chevron, and B. Waltman, SPE, P. Lord, SPE, and T. Goosen, SPE, Halliburton, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 December. The paper has not been peer reviewed.
There has been an increase in the number of wells drilled to depths greater than 20,000 ft in the Gulf of Mexico (GOM). Because of the high fracture gradient and friction in the wellbore tubulars, a conventional 1.0- to 1.04-specific-gravity (SG) fracturing fluid would require surface treating pressures greater than 15,000 psi, which exceeds the limit of the flexible treatment line. To solve this problem, a borate-crosslinked high-density fracturing (HDF) fluid with SG of up to 1.38 was developed to reduce the amount of surface treating pressure required to achieve adequate bottomhole fracturing pressure.

Introduction
The Tahiti field is in the GOM in the Green Canyon area where water depths range from 4,000 to 4,300 ft. The discovery well was drilled in 2002. Total depth was more than 28,000 ft. Initial evaluation indicated approximately 400 ft of net pay in the high-quality reservoir sand that was encountered. Subsequent appraisal drilling over the next 2 years resulted in confirmation of the size of the Tahiti field and its status as one of the most significant net-pay accumulations ever discovered in the GOM. The discovery well was re-entered in 2004, and a well test was performed to verify deliverability, dynamic well data, and reservoir properties. A stacked frac pack in the Miocene M21A and M21B sands was planned for the well test. The Tahiti M21A sand averages 60 to 80 ft thick, and the M21B sand averages 120 to 150 ft thick. Permeability ranges from 600 to 800 md. The decision was made to complete both intervals with a single, high-rate frac pack. At the time, at a depth in excess of 25,800 ft, it was the deepest successful well test and frac-pack completion ever carried out in the GOM. The HDF fluid was a key component of the successful Tahiti well test. The well-test results led to the development of the Tahiti field, which began in February 2006.
While planning the Tahiti well test, several factors influenced the decision to develop a suitable HDF fluid that would minimize surface treating pressures and allow the fracture job to be pumped at pressures below the 14,000-psi limit. Uncertainty regarding Miocene-pay-sand fracture gradients, and required treating rates, coupled with high friction losses in the treating string led to the desire to find an HDF fluid that would allow the fractures to be pumped at 40 to 45 bbl/min while staying within surface-treating-pressure limitations.
Technology Focus: Production Operations (March 2009)
Authors: Alhanati Francisco J.S. 
Published: February 2015

Technology Focus
If you are involved in production operations, you probably are dealing with at least one, likely more than one, of the following tough challenges: deepwater subsea; arctic environment; complex wellbores (e.g., highly deviated, long horizontal sections); high-pressure/high-temperature; heavy/viscous oil; or conditions favoring sand production or deposition of scale, paraffin, asphaltenes, or hydrates; or the formation of tight emulsions. In addition, you also have to figure out the best way to manage the produced water and keep corrosion under control. Hey, this is what makes our jobs fun, right?
Fortunately, despite the hectic pace in the industry these days, many of us are still making time to write papers and make presentations at technical conferences, sharing ideas and hands-on experiences. This past year alone, almost 200 SPE papers related to production operations have been presented. And this number does not include papers that deal specifically with artificial lift, wellbore completions, or production facilities. The papers featured in this issue, therefore, can give you only a small sample of the vast amount of the good material that is out there. Enjoy the reading and search for more at the SPE eLibrary.
Production Operations additional reading available at the SPE eLibrary: www.spe.org
SPE 114106 • "The Cost and Value of Field, Laboratory, and Simulation Data for Validating Scale-Inhibitor-Treatment Models" by J.A. Patroni Zavala, Heriot-Watt University, et al.
SPE 116673 • "Sand or Mud Removal in Low-Bottomhole-Pressure Wellbores Using Jet Pump and Concentric Coiled Tubing Leads to Improved Production" by J. Li, BJ Services, et al.
Additional reading available at OnePetro: www.onepetro.org
OTC 19612 • "Swellable-Packer Technology Resolves Water-Production Problem—Case History in Campos Basin, Brazil" by Eduardo Midulfo Ueta, Petrobrás, et al.
Protect Electrical Submersible Pumps by Squeezing Scale Inhibitors
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115195, "Squeezing Scale Inhibitors to Protect Electric Submersible Pumps in Highly Fractured, Calcium Carbonate Scaling Reservoirs," by Neil Poynton, SPE, Alan Miller, Dmitry Konyukhov, and Andre Leontieff, Baker Hughes, and Ilgiz Ganiev and Alexander Voloshin, SPE, Ufanipineft, prepared for the 2008 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 28-30 October. The paper has not been peer reviewed.
Electrical submersible pumps (ESPs) can increase production rates, but run time can be compromised by the formation of scale inside the pump. Eventually, the pumps fail (either mechanically or electrically) and must be replaced. Examination of failed pumps indicated the main failure mechanism was deposition of calcium carbonate scale inside the pump. Testing was performed to identify and develop scale-inhibitor squeeze chemistries suitable for appli-

Introduction
Yuganskneftegaz is Rosneft's largest oil-producing enterprise. It holds licenses to develop 26 oil fields in the Khanty Mansiysk Autonomous District of western Siberia.
Yuganskneftegaz's primary fields are Priobskoye, Prirazlomnoye, Mamontovskoye, and Malobalykskoye. The number of wells on production in 2006 was 7,707. The average production per well was 21.3 tonne/d in 2006.
Typical well completions in the Priobskoye field have the following characteristics.Internal casing diameter of 131 or 157 mm (a few with 160 mm)Outside diameter of the production string of 73 mm (a few have 80 mm)Pump depth at 2300 to 2800 mDepth to perforation of 2500 to 3000 mPermeability from 3 to 20 md
Produced water has a calcium carbonate scale potential, which negatively affects ESP run time. Testing identified a suitable squeeze inhibitor, and a model of the application identified the squeeze-treatment sensitivities.

Scale-Prediction Modeling
Commercially available scale-prediction software was used to determine scaling tendencies at different pressures and temperatures for brine chemistries from several Priobskoye wells. An understanding of the scaling risk was developed, and suitable scaling brine was identified for use in the subsequent laboratory inhibitor-selection process. Simulations were performed at bottomhole flowing conditions, for estimated ESP internals, and at well-head conditions.
Scale-prediction results for the different wells followed a similar trend. Three scale species were predicted—iron carbonate, calcium carbonate, and barium sulfate. Of these species, barium sulfate was the least significant, and, where present, the tendency was very mild. Calcium carbonate tendencies ranged from moderate to severe. The pH value at standard temperature and pressure also was calculated with the model, and the results correlated very well with the pH measured in the field.
Integrated Approach to Formation-Water Management: From Reservoir Management to Protection of the Environment
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116218, "The Integrated Approach to Formation-Water Man agement: From Reservoir Management to Protection of the Environment," by Jose G. Flores, SPE, and Jon Elphick, SPE, Schlumberger, and Francisco Lopez and Pablo Espinel, Agip Oil Ecuador, prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed.
Most fields in the Oriente basin of Ecuador and neighboring Marañón and Putumayo basins in Peru and Colombia, respectively, produce large volumes of water. In most cases, as the water cut increases, oil production is restricted, which creates production problems including scale deposition, corrosion, and sand production. An integrated approach to formation-water management begins with an understanding of the water-flow mechanisms in the reservoir and identifying the water-breakthrough mechanism at the producer well, followed by the detection of production bottlenecks in the wellbore and surface facilities, and then finishing with analysis of water disposal or reinjection.

Introduction
Villano is a heavy-oil field in a tropical rainforest area in the Province of Pastaza in the Oriente basin of Ecuador. Discovered in 1950, it began producing in 1999. Because of concern for the environment and native communities in the area, development was performed in an offshore-type fashion. With no road access, all transport was provided by helicopter. The drilling and production facilities are limited to two well pads, V-A and V-B of approximately 4 and 2 hectares, respectively. Pad V-A hosts a drilling and a workover rig, drilling warehouses, well pads, living quarters, production facilities to dehydrate the oil, and transfer pumps to transport the oil through a 12-in.-diameter 44-km-long pipeline to the central processing facility (CPF). Formation water is disposed of at Pad V-A into two water-disposal wells (WDWs). Pad V-B is a remote wellsite with limited facilities. Particularly relevant in the effort was construction of the aerial 12-in. pipeline, built without road support and with a minimum effect to the rain forest environment.
The Villano structure was developed primarily with horizontal wells. Sixteen wells have been drilled in Villano—13 producers, all fitted with electrical submersible pumps (ESPs); two WDWs; and one discovery well (V-1), which has been abandoned. There are two additional WDWs at the CPF. All the production is from and water disposal is into the Hollín formation, of Cretaceous age.
Electrical Downhole Heaters for Faja Heavy-Oil Reservoirs
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117682, "Feasibility of Using Electrical Downhole Heaters in Faja Heavy-Oil Reservoirs," by Raul Rodriguez, SPE, Jose Luis Bashbush, SPE, and Adafel Rincon, SPE, Schlumberger, originally prepared for the 2008 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 20-23 October. The paper has not been peer reviewed.
The full-length paper examines use of downhole heaters in thick sands stimulating vertical and horizontal wells, evaluates temporary application of downhole heaters in horizontal wells for a limited period of time, and covers basic economic analyses.

Introduction
The Orinoco belt (Faja) in Venezuela contains one of the largest resources in the world of heavy and extraheavy oil. Because of the production decline of conventional light crude, projects must focus on increasing the recovery of heavy and extraheavy oils by use of thermal and nonthermal methods. Steam-based thermal-recovery processes are more efficient in low-pressure reservoirs; however, because of their depth, the initial pressures of the reservoirs in the Faja are relatively high, ranging from 600 to 1,500 psi with viscosities typically greater than 2,000 cp. For these reasons, it is important to decrease the pressure of the reservoirs with primary-production techniques to facilitate the economical implementation of steam-injection-based methods.
The initial production of heavy and viscous oils can be accelerated by use of downhole heaters that, by providing energy to the vicinity of the well, decrease oil viscosity and increase the oil-production rate. A consequential advantage of using downhole heaters as a prelude to a steam-injection process is that they accelerate early production and reservoir-pressure depletion.

Electrical Downhole Heaters.
Electrical heating consists of providing electrical currents to generate heat and increase the temperature near the wellbore. There are two kinds of downhole heaters in use by the oil industry: inductive heaters, generating heat in accordance with Maxwell's law, and resistive heaters that generate heat in accordance with the Joule effect. In the latter case, the heat transfer is by conduction and it requires an extended time period to heat the reservoir.
In this study, the resistive heater is modeled with the aid of a numerical thermal simulator. This type of heating process stimulates oil recovery primarily by reducing the oil viscosity in the near-wellbore region and secondly by thermal expansion of reservoir fluids. The key parameters to be understood in this process are the heavy-oil-viscosity variation with temperature and the rate of heat provided by the heater associated with the generated temperature gradient in the volume around the well. Heat output from resistive heaters typically ranges from 14 to 730 W/ft (1,100 to 60,000 Btu/D/ft). A maximum-exposure temperature normally is imposed on the heaters.