bluuebunny/crossref_metadata_2025_split huggingface dataset:
Polymer-Flooding Pilot Finds Success in Previously Waterflooded Reservoir
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166255, ’Polymer-Flooding-Pilot Learning Curve: 5+ Years' Experience To Reduce Cost Per Incremental Barrel of Oil,’ by J. Buciak, SPE, G. Fondevila Sancet, and L. Del Pozo, Grupo CAPSA, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
A successful pilot test of polymer flooding was conducted in the San Jorge Gulf basin, a mature waterflood with the presence of heterogeneous reservoirs and viscous oil under reservoir conditions. During the past 5 years, 3,200 tons of hydrolyzed polyacrylamide polymer was injected at concentrations of 1,500 ppm. The polymer flooding resulted in an increase in oil production to 100% and a decrease in water production to 50% in original central wells.
Introduction
The Diadema oil field is in the San Jorge Gulf basin in southern Argentina. The field has 480 producer wells and 270 injector wells. The reservoir being polymer flooded is characterized by high permeability (an average of 500 md), high heterogeneity (10–5,000 md), high porosity (30%), very stratified sandstone layers (4–12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp under reservoir conditions).
Record ERD Well Drilled From a Floating Installation
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98945, "World-Record ERD Well Drilled From a Floating Installation in the North Sea," by A. Hjelle, SPE, T.G. Teige, SPE, K. Rolfsen, K.J. Hanken, SPE, and S. Hernes, SPE, Statoil, and Y. Huelvan, Schlumberger, prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February.
Well 34/8-A-6 AHT2 was drilled from the Visund field floating production and drilling unit (FPDU) in the North Sea with initial production in October 2005. The well was drilled to 9082 m measured depth (MD) and has an along-hole depth of 7593 m.

Introduction
The Visund oil/gas field is 150 km offshore the west coast of Norway in a water depth of 335 m. The field was discovered in 1986, with first production in 1999. The depth of the main reservoir is 2900 to 3000 m true vertical depth (TVD), with a maximum pore pressure of 434 bar. The field is 24 km long and 4 km wide. With this field shape, extended-reach-drilling (ERD) wells drilled both to the north and to the south will increase drainage area and thereby the total recovery from the field. The Visund FPDU is centrally located over the field. The Visund North satellites consist of two wells tied back to the FPDU with a 9-km-long subsea pipeline.
In the early preplanning phase, the subject well was planned as a separate subsea development, drilled by a separate semisubmersible rig. A new technical and economical study showed that this well could be drilled more economically from the existing Visund FPDU, through existing subsea systems. Fig. 1 shows the well profile.

Planning Phase
The planning phase of this well was performed by use of the continuous-improvements model (Fig. 2). The first plan recommended drilling for a separate subsea-development well. After gaining experience, it was decided that the well could be drilled from the Visund FPDU. The drilling plan was completed together with a separate risk document covering critical events that could be identified before drilling the well. This risk identification process was performed in a workshop together with the service companies and the drilling-contractor personnel working on the Visund field. The detailed rig procedures that were to be used on the rig floor also were prepared onshore in the same type of workshops. This proved to be a good way of building a committed team and identifying risks and parallel activities that could be prepared before the operation.
Peer assist and review were performed on this well to ensure that relevant experiences were included in the planning phase. After the well was completed, a final well meeting was held with the involved service companies ensuring that relevant experiences were recorded for the next well.
Q&A with Jacques Bosio
Authors: Bosio Jacques , Donnelly John 
Published: February 2015

Editor's Note: In recognition of SPE's 50th anniversary this year, JPT is conducting interviews with several Society luminaries about their careers, their relationship with SPE, and the changes they have seen in the oil and gas industry and the Society over the past several decades.
In 1993, you became the first person outside of the United States to hold the office of SPE President. What was the significance of this and was its significance realized at the time?
SPE was perceived as 100% US at the time. But SPE was opening new sections every year outside the US already and appeared to be going in that direction. But, let us face it, I would say that one half of the SPE Board of Directors was not very much in favor of becoming totally international. Fortunately, some Presidents before me—such as Orville Gaither (1990) and Kenneth Robbins (1985)—had vision and realized that the central gravity of the oil business was moving east. Because of the North Sea, which was being developed, and of course, the Middle East, Texas was no longer the center of gravity. So it was really time to integrate the rest of the world into SPE, and it was also time to make it known that SPE had evolved and was truly becoming international.
So the idea of a non-US President would be a symbol and I think it worked. When our members opened up their JPT one month, they had proof that SPE was going international, since the least you can say about a Frenchman is that he is a true foreigner! It was a sign of a clear evolution.

Was there much reaction from the membership?
The reaction was positive. SPE had opened a new section in France in the 1980s and in other areas already. As I traveled around—to Norway, to Great Britain, and to other places—the members all said they found the idea of SPE becoming more international to be a very good one.

Looking back, what are your thoughts about the pace of SPE's international growth? Did it happen too slowly? At about the right speed?
Certainly not too slowly; it was an evolution, not a revolution. SPE was already on the right track, and since my term, there have been several non-US presidents. Look at what SPE has become in 15 years—half of the members are now outside the US, we have sections all over the world, and we have opened several offices outside of the US. All of this growth went together with the technical revolution in communication, which was very expensive, along with the creation of a bunch of new meetings all over the world. If you think about it, if it takes 20 years to make an adult, then 15 years to do what SPE has done is not a very long time. In 15 years, we have gained international recognition and respect. It has been a fantastic success.
Overview: Well Stimulation (July 2007)
Authors: Hager Charles 
Published: February 2015

For this month's issue of featured well-stimulation papers, the ongoing work in acidizing earns my recognition as the most enlightening and yet overdue progress. Although the papers spotlighted in this issue are strong presentations on diverse subjects, I was most surprised by the volume of engaging papers focusing on acids and fracture acidizing. There are great papers in my list with information on horizontal wells, gravel packing, and viscoelastic fluids; however, each of these technologies is young compared to acidizing reservoir rock.
In one of the additional-reading selections, "Fracture Acidizing: History, Present State, and Future," we learn that acidizing carbonates dates back to 1895. Therefore, the use of acids to increase production is more than a century old. With many of the modern acidizing theories developed around 1972 by Neirode and others, it is still a 35-year-old technology that needs a fresh look with modern methods. Whether we are studying etching behavior to forecast conductivity or predicting long-term reductions in performance caused by creep, we still have a lot to learn about this venerable practice.
Therefore, the question becomes: "How can acidizing oil wells be more than 100 years old, yet we just now are beginning to unravel these fundamental concepts?" The world produces approximately 85 million BOPD, and assuming just USD 50/B, we generate more than USD 1.5 trillion/yr in world oil revenue. Whatever the historical disconnect has been between oil revenues and funding oil science, I am pleased to recommend these compelling technical papers on subjects vital to our industry, including the common practice of pumping acid into a formation to increase production.
Well Stimulation additional reading available at the SPE eLibrary: www.spe.org
SPE 108075 "Horizontal-Well Completion and Stimulation Techniques—A Review With Emphasis on Low-Permeability Carbonates" by Valdo Ferreira Rodrigues, SPE, Petroleo Brasileiro, et al.
SPE 107772 "The Effects of Acid Contact Time and the Resulting Weakening of the Rock Surfaces on Acid-Fracture Conductivity" by M.G. Melendez, Texas A&M University, et al.
SPE 107760 "Acid Stimulation of Extended-Reach Wells: Lessons Learnt From N'Kossa Field" by J.M. Mazel, Total, et al.
SPE 106371 "Fracture Acidizing: History, Present State, and Future" by Leonard J. Kalfayan, SPE, BJ Services
Overview: Multilateral/Extended Reach (July 2007)
Authors: Mason Colin 
Published: February 2015

ExxonMobil recently announced a new world record for extended-reach drilling at its Chayvo development on Sakhalin Island. This achievement started me thinking: How can exceptionally long wells be drilled and completed in some areas but not in others? The answer to this question is highly complex and is driven by a large number of interdependent variables. Assuming that a drilling rig large enough to supply the required mechanical and hydraulic loads is available, essentially what remains is the nature of the subsurface environment. Usually, it is this factor that holds the key to understanding whether extended-reach-drilling techniques will be viable. Therefore, the use of fit-for-purpose drilling practices and deployment of technology also play a vital role.
The key challenge, therefore, is to understand the complexity of the subsurface environment and its compatibility with extended-reach-drilling techniques. Information on rock type and strength, field-stress orientation, pore pressure, fracture gradient, fractures and faulting, and bedding planes helps form a representation of subsurface risks. Developing a workable and relevant definition of subsurface complexity, applicable to extended-reach wells, would be of high value to the industry, but it would likely be a nontrivial exercise.
By comparison, the multilateral community developed the Technical Advancement of Multilaterals (better known as TAML) classification system that accounts for the complexity of a junction as well as the well type and junction description. In this case, there appears to be a good correlation between complexity and degree of difficulty of successfully installing the junction.
Looking to the near future, the potential is immense for downhole broadband technology to telemeter wellbore conditions continuously in real time together with the use of sophisticated interpretative techniques. This technology could well be an enabler for effective delivery of the industry's most challenging wells.
Multilateral/Extended Reach additional reading available at the SPE eLibrary: www.spe.org
SPE 104623 "Application of Novel Technology Improves Drilling Performance in Multilateral Field Development Offshore West India—Reducing Risk and Increasing Production" by Anil Jaggi, SPE, BG Group, et al.
SPE 105715 "Drilling and Completing Intelligent Multilateral MRC Wells in Haradh Inc-3" by Fahad Al-Bani, SPE, Saudi Aramco, et al.
SPE 104192 "Transport of Small Cuttings in Extended-Reach Drilling" by Mingqin Duan, University of Tulsa, et al.
Innovative Chemical and Mechanical Processing for Treatment of Difficult Production-Waste Sludge
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105584, "Application of Innovative Chemical and Mechanical Processing for Treatment of Difficult Production-Waste Sludge," by Jacquelyn F. Star, Chevron; Stephen Williams, SPE, M-I Swaco; Isham Sudardjat, Chevron; Roger Kidder, M-I Production Chemicals; and Darrell L. Gallup, SPE, Chevron, prepared for the 2007 SPE E&P Environmental and Safety Conference, Galveston, Texas, 5–7 March.
East Kalimantan field in Indonesia has experienced challenges in managing and treating emulsions, slop oils, slurries, and tank bottoms that accumulate in process vessels and tanks. Previous disposal methods did not provide oil recovery and posed severe environmental or regulatory problems. A viable treatment process that uses an aggressive system of heat, customized chemical demulsification, settling, and various means of mechanical/centrifuge separation was developed and put in place. The system recovered more than 40,000 bbl of oil.

Introduction
Oil and gas producers in the Kutei basin of east Kalimantan, Indonesia, have had difficulties in the management of slurries, slops, and sludges accumulated in process vessels and storage tanks. Unresolved production byproducts, collectively termed sludge, have strong oil/water emulsions, chemically bound by naturally occurring soaps and various mixtures of stabilizing fine sand, scale, and wax. These various production wastes can be exceptionally challenging to treat and recover.
Treatment and reclamation of more than 317,000 bbl of tank sludge from the Santan secondary-impoundment-area (SIA) pit from August 2004 through September 2005 targeted the following:Treat the sludge with 100% efficiency, converting the waste to oil, solids, and acceptably clean water.Treat the sludge and close the pit as quickly as possible.Maximize oil recovery and reduce overall treatment costs.Develop a safe, environmentally superior process for sludge treatment that could be considered the standard for best practice for subsequent operations.

Background
Santan terminal has been receiving, processing, and storing oil and gas from offshore shelf fields for approximately 30 years. Because of chemistries unique to the Kutei basin of east Kalimantan, production fluids have a tendency to form a type of carboxylic soap, leading to strong emulsions of the oil and water phases. These emulsions can be further stabilized by fine scale, formation flour, and wax. With enough solids entrainment, these emulsions can sink, creating a mud-like sludge.
It is estimated that unresolved emulsions are dumped to the water plant at a rate of up to 400 B/D (where they are pumped to a designated sludge tank) or are deposited into the storage tanks. This sludge waste represents more than 40,600 bbl of oil in the SIA.
Comments: Price Drivers
Authors: Donnelly John 
Published: February 2015

Editor's column
Two reports released last month help explain the dramatic rise in oil prices this year. The price of Brent, the world's dominant marker crude, has almost doubled in the past year and is up more than 40% since the start of this year. The weak dollar, the flow of money from other financial sectors to oil, and geopolitical blips may be responsible for some of the increase, but the real reason appears to be the basic fundamentals of supply and demand.
The 57th edition of BP's annual Statistical Review of World Energy shows a global market tightly balanced, with little room for error. Last year, global oil production fell by 0.2%, the first decline in world output since 2002, while consumption increased 1.1%. World production decreased 130,000 BOPD to 81.53 million BOPD. OPEC production cuts accounted for some of that drop, but output in OECD countries fell 300,000 BOPD, reflecting aging oil fields. Some of the world's major oil provinces are posting production declines—including the North Sea, Russia, and Mexico—and may continue to fall. North Sea output has been declining since 1999 and Mexico's giant Cantarell field is in rapid decline. During this year's Offshore Technology Conference, Pemex Director General Jesús Reyes-Heroles acknowledged that the company's objective of maintaining crude output at 3.1 million BOPD through 2012 will be severely tested by the challenge to compensate for Cantarell's decline.
Demand grew by approximately 1 million BOPD, according to BP's review, with consumption strong not only in Asia but in large oil-exporting regions such as the Middle East, South America, and Africa, which could limit exports to major consuming centers. Consumption growth slowed last year, due to weaker economies and higher prices, but was still above the 10-year average for the fifth year in a row. Oil prices have risen for 6 years in a row, the longest period of rising prices on record, according to BP, and are certainly on track to finish the year higher again.
Similarly, the International Energy Agency's (IEA) most recent report notes lower global consumption than previously forecast, but predicts demand this year rising to almost 87 million BOPD, about 1% higher than last year. The IEA also revised down its estimates of non-OPEC production for this year, bad news for a tight global supply balance. Demand from developing countries continues to rise, which has pushed the energy sector into a whole new realm, according to Lane Sloan, a longtime Shell executive and author of the new book, Terra Incognita: A Navigation Aid for Energy Leaders. The population of China and India together is 2.4 billion, compared to the OECD population of 1.2 billion, and those nations are going through the industrialization process that OECD countries went through last century. As historian Daniel Yergin has noted, of all the interesting characters in the history of the oil industry, perhaps the two most significant are supply and demand.
Innovations for Deepwater Jubarte Heavy Oil
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19083, "The New Deepwater Oil and Gas Province in Brazil: Flow Assurance and Artificial Lift: Innovations for Jubarte Heavy Oil," by Giovani Colodette, Carlos A.G. Pereira, Cezar A.M. Siqueira, Geraldo A.S.M. Ribeiro, Roberto Rodrigues, Joao S. de Matos, and Marcos P. Ribeiro, Petrobras, originally prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
The full-length paper presents a review of the artificial-lift (AL) and flow-assurance challenges faced in the exploitation of Jubarte heavy oil, starting from the features of the Pilot Phase. The challenges posed and innovations proposed and implemented for Phase 1 field development, as well as expectations for the subsequent Phase 2, are detailed.

Introduction
The Jubarte field is in the north part of the Campos basin, approximately 80 km offshore from the state of Espírito Santo, at a water depth between 3,280 and 4,922 ft. The field discovery occurred in January 2001, when an interval containing 17°API oil was identified in sandstones of Maastrichtian age.
During the evaluation phase, a study based on the concept of value information supported the decision to drill a horizontal appraisal well. In February 2002, the well was drilled, with a 3,510-ft horizontal length, and was completed with an openhole gravel pack. The result was a well productivity index (PI) 13 times greater than the PI obtained with the vertical well. An extended well test (EWT) was proposed and approved. In the EWT, which started in October 2002, Petrobras made use of the floating production, storage, and offloading (FPSO) vessel Seillean, a dynamically positioned vessel with a rig capable of performing light workover operations. The well was connected to the FPSO through a 5 5/8-in.-inside-diameter drillpipe riser. Using an innovative solution, a 900-hp, 25,000-B/D-capacity electrical submersible pump (ESP) was installed above the wet tree. In case of ESP failure, the drillpipe riser could be recovered by the FPSO for pump retrieval and replacement. The good results obtained in the EWT led to its continuation in a Pilot Phase, which lasted until January 2006.
After the Pilot Phase, the Jubarte Phase 1 production was started with the FPSO P-34. This new development phase comprises four production wells, and a 60,000-B/D oil-production rate is expected. One of the wells represents an innovative installation of the ESP on the seabed, another well has a downhole ESP installed, and the remaining two wells produce with gas lift (GL). GL backup can be used in the ESP wells while awaiting repair in case of pump failure.
The ultimate Jubarte production system (Phase 2), to be implemented in 2011, will comprise 11 new wells plus the four wells from Phase1, and seven water-injection wells, connected to the FPSO P-57. During this production phase, all production wells will run ESPs installed on the seabed as the main AL method, with GL as backup.