bluuebunny/crossref_metadata_2025_split huggingface dataset:
Through-ESP Stimulation: A Cost-Effective Alternative
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112315, "Through-Pump Stimulation: A Cost- Effective Alternative," by K.I. Ojukwu, SPE, Petroleum Development Oman, prepared for the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 13–15 February. The paper has not been peer reviewed.
A major disadvantage of electrical submersible pumps (ESPs) is that they block access to well re-entry for surveillance and through-tubing intervention. One case of the latter is acid stimulation. In Petroleum Development Oman (PDO), acid jobs have been carried out as part of work-overs to retrieve the pumps first. The cost implication can be large, ranging from USD 250,000 to 400,000. Two deployment techniques were adopted in PDO recently, bullheading acid into the reservoir through an ESP and spotting acid through coiled tubing (CT) into the reservoir; by so doing, 80 to 93% of comparative cost was saved. The techniques involved the use of abrasion-resistant ESPs for vertical wells and an ESP bypass (Y-tool) for CT deployment in horizontal wells.

Introduction
The X field in Oman is a sour, low-pressure carbonate formation 600 m deep and under natural depletion since the early 1970s. The field suffered a sharp pressure decline early, leading to installation of gas lift in all wells. By the mid-1990s, the remaining producers were converted to ESP wells because of gas-supply constraints. Gross production increased by more than 200%, and water cut increased from 50 to 80% at that time. A total of 18 wells are completed in this carbonate formation, which includes three cased horizontal and two openhole observation wells. By 2006, only four of these wells were producing, with an 80% average water cut. X-field wells are characterized by high productivity indices (PIs) of 1 to 4 m3/(kPa.d), mainly a result of an active fracture network and faulting. Almost all matrix-completed wells did not produce, causing all production to be from the fracture and fault network.

Game Change
Several matrix wells had been treated with acid after drilling and before production but still did not produce sustainably. To obtain the best results from acid treatments, spent acid should be removed from the well soon after the treatment, which usually is not a problem in wells that produce naturally. However, in low-pressure wells completed with pumps such as ESPs, post-stimulation acid pumpout is hardly possible and has not been a standard practice. This game change was necessary to exploit matrix production in the X field and would mean developing new ways to deploy acid effectively at a reasonable cost and yet with capability to pump out spent acid in time to avoid further reaction or damage (within 1 to 2 hours).
Your SPE: Updates: Meetings Innovations, India Visit
Authors: Roodhart Leo 
Published: February 2015

President's column
The world is still in a crisis, and SPE is beginning to see consequences. Some of our conferences and workshops have seen fewer attendees. However, membership growth doesn't seem to be affected much.
Financial crises are strange creatures. When I visited the Vietnam Section in April, section secretary Ben Gedge made a very wise observation. He said that most of us can live very happily without buying anything new for the next 2 years. However, if we do that, he said, of course the people who manufacture those new things have less income and they will also delay buying "new things," which will cause the global economy to continue its downward spiral, and there is your crisis. This is exactly what is happening at the moment. Many of our members’ companies are "managing" costs by delaying expenditures, including those for learning/networking events like our conferences and workshops. This is a dangerous path, as it will create a downward spiral in knowledge dissemination, where knowledge and global cooperation is key to our industry if we want to continue to provide the world with energy when demand picks up. SPE therefore is trying to break this spiral in a number of ways and has taken a number of actions, mainly to reduce need for travel for members.
One example was piloted in the Gulf Coast Section's recent Digital Energy Conference in Houston, where we held a parallel conference in Second Life. Instead of being there physically, the authors presented their papers "virtually" via the Internet, through their avatars in Second Life. The Second Life conference was presented to the audience in Houston on a big screen.
In March, we used Webex and Skype to bring a presenter in Colorado, USA, to workshop attendees in Queensland, Australia. Remote presentations with interactive audience participation were also done at our May workshop on IOR Petrophysics in Cairo. No visitors yet in a "virtual presentation room," but that could be the next step.
Second, SPE will also bring meetings/workshops/conferences closer to where the members are. So, we will hold very few conferences in fancy places, and, if practicable, more in major industry centres like Amsterdam, Aberdeen, Houston, and Kuala Lumpur.
Third, we will webstream key presentations from large conferences, so that anyone can follow the presentations in his/her own office on the computer screen. More innovations may come, and I am open for suggestions.
In the long run, conferences and workshops without real people will not be easy to sustain, as building a network is an important aspect of those events. However, we believe that for the next 1 to 2 years this will work and we will put a lot of effort into finding new ways to bring people together, such as SPE virtual networks, discussion groups, etc.
Formation Mineralogy Affects Scale-Inhibitor Squeeze Designs
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113261, "Formation Mineralogy Impacts Scale-Inhibitor Squeeze Designs," by Rick Gdanski, SPE, Halliburton, originally prepared for the 2008 SPE Europec/EAGE Conference and Exhibition, Rome, 9-12 June. The paper has not been peer reviewed.
Scale-inhibitor squeeze designs often are developed using short-core laboratory flow tests for estimating treatment life and fluid/rock compatibility. Laboratory tests provide a relatively high level of successful squeeze designs. However, occasionally, squeeze treatments cause unexpected production loss and have a short squeeze life. The full-length paper discusses how formation mineralogy can improve successful designs of squeeze treatments even before laboratory tests are conducted. A radial model was used to demonstrate key principles of optimizing treatments.

Introduction
Prevention of formation damage and plugged perforations caused by scaling brines is a common challenge for producing wells. The consequences of uncontrolled scale can be particularly costly in offshore subsea installations. Deposits that can occur in the formation near the wellbore and in the tubulars often are mitigated with scale inhibitors by squeezing them into the formation. It might be expected that there would be an optimum "normalized" squeeze design that would be applicable for nearly all formations. However, this is not the case because of the variation in formation mineralogy. Squeeze designs that work very efficiently at preventing scale in one area may not provide the same performance in another area. Unfortunately, squeeze treatments that show no damaging effects in one formation may show extensive production loss in another. The work described in the full-length paper was conducted to demonstrate a systematic approach to designing scale-inhibitor squeeze treatments on the basis of formation mineralogy, porosity, water-production rate, and minimum inhibitor concentration (MIC).

Formation Mineralogy
Often, it is tempting simply to consider a sandstone formation as having a generic composition, consisting mostly of quartz with some feldspars, clays, and perhaps some carbonate. However, the specific compositions of the nonquartz mineral groups can be very important in understanding fluid/rock interactions, acidizing challenges, and scale-inhibitor adsorption and desorption.

Smectite.
Some formations respond poorly to weak brines because of clay swelling. Smectite often exists as a separate mineral. However, it is more often found in the form of mixed-layer (ML) illite-smectite clay. Not all ML clays are swellable, and so a number often is included to indicate the percentage of swellable smectitic layers. As such, ML(35) indicates an ML illite-smectite clay having 35% swellable layers. In general, smectitic clays will begin to swell when the sodium chloride (NaCl) concentration falls below approximately 6%.
Technology Focus: Coiled Tubing Applications (June 2009)
Authors: Misselbrook John 
Published: February 2015

Technology Focus
It is difficult to maintain an upbeat attitude when faced with the significant reduction in activity we have seen over the past few months resulting from the dramatic decline in oil and gas prices. So it was with a measure of uncertainty that I reviewed the papers being considered for this month's feature. However, while I was reading the papers, a theme began to suggest itself.
As I reflected on the technologies developed by the coiled-tubing (CT) practitioners during the past growth cycle, there appeared to have been a large effort invested in ever-more-sophisticated tools and hardware. It seemed that the purpose was not to reduce daily operating rates but instead to reduce the number of operating days (or hours). In fact, the role of technology in our industry in general has, more often than not, focused on delivering value rather than lower prices per se.
While delivering greater value will always be a key objective in the evolution of technology, the reality is that we must be more innovative when the drilling and intervention budgets are under extreme pressure and we must also find solutions that are lower in actual cost.
Accordingly, the papers I selected for this issue are examples of using old ideas in new ways. These are simple, low-cost techniques brought up to date and reapplied to current problems.
The advantage we have today is better instrumentation at the wellsite and the existence of powerful software models that allow us to examine system response to specific intervention actions. By this means, "old" ideas can be applied with a level of reliability previously unobtainable. Let us all hope that this trend can be maintained.
Coiled Tubing Applications additional reading available at the SPE eLibrary: www.spe.org
SPE 121343 • "Optimization of Milling Plugs With Coil Tubing on the Pinedale Anticline" by Brian Perry, Shell E&P Americas
SPE 121752 • "Modeling the Effect of a Downhole Vibrator" by Ken Newman, National Oilwell Varco, et al.
SPE 121736 • "Optimizing the Most Common CT Operation in the US: Findings From More Than 60 Composite Frac Plug Underbalanced Milling Operations in the Piceance Basin" by L. Castro, SPE, BJ Services, et al.
Maximizing Energy at Coalface for Coalbed-Methane Fracturing
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 114974, "Maximizing Energy at Coalface for Coalbed-Methane- Fracturing Operations," by Abbas Mahdi, SPE, Schlumberger; Mike Yu, SPE, EnCana; Doug Pipchuk, SPE, Craig Wasson, SPE, Jim Nguy, SPE, and Nathan Kathol, Schlumberger, originally prepared for the 2008 CIPC/ SPE Gas Technology Symposium Joint Conference, Calgary, 16–19 June. The paper has not been peer reviewed.
Nitrogen coiled-tubing (CT) fracturing is the predominant method for completing and stimulating dry-coalbed-methane (CBM) formations, such as the Horseshoe Canyon in the west-ern Canadian sedimentary basin. Currently, energy that can be delivered to the coalface of these dry-CBM wells has been limited by the frictional pressure loss through CT. The full-length paper discusses the development of a technique that releases a large-volume pressure pulse downhole during the fracturing process to create an order-of-magnitude change in available energy at the fracture face.

Introduction
The Horseshoe Canyon dry-coal formations have been exploited commercially since late 2000. The Horseshoe Canyon CBM play is a unique CBM play, in that it consists of a dry underpressured coal, which does not require dewatering before production. The coal consists of multiple thin seams, ranging from 10 to 30 seams per well, that are treated individually. Coal-seam thick-ness ranges from 0.1 to 2.5 m.
The production rates from these CBM wells dictate that an efficient drilling and completion model be adopted to be economic. The wells are drilled with CT drilling rigs, cased, and cemented. Wireline perforating crews perforate the zones of interest in a rigless operation. The individual coal seams then are stimulated by injection of dry nitrogen at high rates through a CT reel equipped with a fracturing isolation tool. The dry coal has not responded well to any other form of stimulation.
To optimize the completion process, high-rate nitrogen-pumping units were developed to reduce the footprint and cost and to increase efficiency of the operation to the point where one and a half to two wells can be stimulated per day. Since the introduction of that change, various optimization initiatives have been attempted. The optimization of nitrogen-pumping rates and pumped volumes has been the focus of these attempts. High rates have been limited by the inside diameter of the CT string. Several CT sizes have been used for this application. Economics and logistics have limited the CT size for CT fracturing to 2 7/8 in. for deeper wells and 3 1/4 in. for shallow wells. The migration to bigger pipe did pro-vide some reduction in frictional pressure loss, but effective pressure at the coalface still was not transported from the surface efficiently.
Technology Focus: EOR Operations (June 2009)
Authors: Bonet-Cunha Luciane 
Published: February 2015

Technology Focus
Welcome to the Enhanced Oil Recovery (EOR) Operations feature. This past year provided stimulating and rewarding times for all involved with EOR technologies. The interest in EOR technologies is higher than ever, despite the current fall in global crude-oil prices, which, by the way, is believed to be temporary by most analysts. This amplified attention in the EOR area results from the decrease of new discoveries and the ever-increasing number of maturing fields worldwide. It is expected that many EOR projects planned in the recent past will be implemented in the coming years. Thus, it is fundamental to revisit the lessons learned from previous EOR applications and to pay attention to the development of new techniques.
Regarding technical publications, this past year alone, more than 300 SPE papers related to EOR were presented at various SPE events. As a result, the EOR feature is divided this year: EOR Performance and Modeling published in January and EOR Operations published in this issue. The papers featured here will give you only a few examples of the immense amount of high-quality material that was published last year. I hope that you enjoy reading these paper highlights and that you will search for additional interesting contributions that are available in the SPE eLibrary (OnePetro as of 1 July 2009).
IPTC 11613 • "Blending Optimization of Contaminated Gas in a Miscible Gasflood" by J.T. van Berkel, SPE, Shell International E&P, et al.
Characterize Scaling Damage From Pressure Measurements
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 112500, "A New Method To Characterize Scaling Damage From Pressure Measurements," by T. Carageorgos, M. Marotti, and P. Bredrikovetsky, SPE, North Fluminense State University, prepared for the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 13-15 February. The paper has not been peer reviewed.
Productivity-decline prediction is based on mathematical modeling with well-known model coefficients. The sulfate-scaling system contains two governing parameters: the kinetics coefficient, λ, characterizing the velocity of chemical reaction, and the formation damage coefficient, β, showing how the permeability decreases because of salt precipitation. This paper extends previous works with commingled injection of two incompatible waters into the same core with two different ratios of formation water (FW) to seawater (SW).

Introduction
Barium- and strontium-sulfate scaling is a major problem in waterflood projects with incompatible formation and injected waters. Barium sulfate and resulting scale causes formation damage near the production-well zone. This phenomenon is attributed to precipitation of barium and strontium sulfates from the mixture of both waters and the consequent permeability reduction resulting in loss of well productivity. The chemical incompatibility between the injected SW, which is high in sulfate ions, and the FW, which originally contains high concentrations of barium, calcium, and/or strontium ions, may reduce well productivity, making the waterflood project uneconomical.
A reliable model that is capable of predicting such scaling problems would help in planning a waterflood project. It also could aid in selecting an effective scale-prevention technique by predicting scaling tendency, type, and potential severity. A reliable predictive model must use well-known values of the model coefficients.
The mathematical model for sulfate scaling contains two phenomenological parameters: λ from the active-mass law of chemical reaction showing how fast the reaction and precipitation occurs, and β reflecting the permeability decrease caused by sulfate-salt deposit. Both coefficients depend on rock-surface mineralogy, pore-space structure, temperature, and brine ionic strength. Therefore, they cannot be calculated theoretically for natural reservoirs and must be deter-mined from laboratory corefloods.
Reagent- and deposition-concentration profiles during reactive flows are nonuniform, so the sulfate-damage parameters cannot be calculated directly from laboratory measurements. They must be determined from laboratory coreflood data by use of inverse-problem solutions.
The λ can be calculated from break-through concentration in a quasisteady-state coreflood with commingled injection of FW and SW. Then β can be determined from the pressure-drop increase during flooding.
Overview: Well Stimulation (July 2005)
Authors: Dusterhoft Ron 
Published: February 2015

Well, it never fails. All good planning aside, here I am preparing this stimulation overview on an airplane the day before it is due. I am reminded of being back in school, but only briefly because the issues that seem to be facing myself and many others in our industry today are more and more demanding and time-consuming than they were back in school. As a result, items such as this tend to slip right to the point where they suddenly become a major priority just when they need to be completed.
Reviewing the papers for this year’s selections, however, was no small task. There were many, many very good quality papers written on a very wide range of stimulation-related topics from locations around the world. This year, being limited to four primary selections meant that four very good papers had to be listed as additional reading, and I strongly recommend that you consider reading these papers.
I was struck this year by the amount of diversity that exists in the subject we call “stimulation” in our industry. In the rather large group of papers that were evaluated for this section, the wide range of subject matter clearly demonstrated how different geographic regions often require different well architecture and different stimulation solutions. It appears that the industry has matured tremendously over the years and that we clearly have developed specific areas of expertise to address specific requirements. With this specialization happening in our industry, it is becoming more important for us to communicate effectively to learn from one another’s experience. I think that it is quite difficult to maintain expertise over a subject as broad as stimulation, but it is important for us to keep well informed because of continuous technical developments on several fronts.
In the selections this year, I tried to pick papers from different locations where our industry is active to demonstrate the types of difficult problems being addressed and the creative solutions being used.
I hope that you will find this section to be enjoyable and beneficial in helping you develop your own solutions for your own well conditions.
Available from the SPE eLibrary: www.spe.org
SPE 90815 - “Injection-Well Stimulation: Putting Away More for Less in California Waterfloods,” by Don McClatchie, SPE, BJ Services Co., et al.
SPE 90428 - “Fine-Scale Simulation of Sandstone Acidizing,” by C. Li, U. Texas at Austin, et al.
SPE 90158 - “The Keys to Successfully Acidizing Horizontal Injection Wells in the Marlim Sul Field,” by Mário Germino Ferreira Da Silva, Petrobras, et al.
SPE 90792 - “Integrated Process Improves Production of the Almond Formation in the Wamsutter Field, Wyoming: A Low-Permeability Case Study of 5 Years of Continuous Improvement in Well Performance,” by Mike Mullen, Halliburton, et al.
Optimizing Fracturing-Fluid Cleanup in the Bossier Sand
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90030, "Optimizing Fracturing-Fluid Cleanup in the Bossier Sand Using Chemical Frac Tracers and Aggressive Gel-Breaker Deployment," by R. Sullivan, SPE, Anadarko Petroleum Corp.; R. Woodruff, SPE, ProTechnics Div. of Core Laboratories; A. Steinberger-Glaser, SPE, and R. Fielder, SPE, Anadarko Petroleum Corp.; and M. Asadi, SPE, ProTechnics Div. of Core Laboratories, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Proper fluid and proppant placement are critical to a successful propped-fracture stimulation treatment. Even with effective treatment placement, well performance often is affected detrimentally by incomplete gel breaking and fluid recovery. A technique that uses a family of environmentally friendly, fracturing-fluid-compatible chemical tracers has been used to quantify segment-by-segment fracturing-fluid recovery. With this technology, individual-fluid-segment cleanup and recovery can be enhanced by optimizing fracturing-fluid selection.

Chemical Fracture Tracers (CFTs)
Chemical fracture tracing was developed to increase the understanding of the dynamics of hydraulic-fracture placement and fluid flowback/cleanup. Borrowing from many years of experience with interwell tracing, several families of nonradioactive chemical compounds were identified that could be placed in segmented portions of the fracture fluid to measure the flowback efficiency of each fluid segment. CFTs are designed to be placed in chemically differentiated and/or proppant-differentiated fluid segments of the fracturing fluid to assess the cleanup of the fracture as a function of segment fluid chemistry and/or fracture geometry.