bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Anchor Extends Insertable Progressing-Cavity-Pump Applications
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
In artificial-lift applications, a new anchoring device for insertable progressing-cavity pumps (I-PCPs) extends I-PCP applications to a larger set of candidate wells. The I-PCP anchor allows an I-PCP to be run, landed, operated, and removed from a tubing string in the absence of a previously installed pump-seating nipple (PSN) typically required for installation.
Conventional PCPs are installed by running the stator assembly on the bottom of the tubing string and the rotor on the bottom of the rod string. In contrast, with an I-PCP, the entire pump assembly is installed by the rod string and landed inside the tubing string. This allows the pump to be pulled and rerun by the rod string. The primary advantage of this system is the elimination of costly and time-consuming tubing pulls to change worn or damaged pumps or to switch to different pump sizes and configurations as downhole pumping requirements change.
I-PCPs are conventionally installed with a PSN in the tubing string and a corresponding set of seating rings in the pump assembly. While this method provides a reliable method of landing, it also requires that the PSN be originally installed and it limits the positioning of the pump to the associated pump-seating location.
Weatherford’s Flexisert I-PCP anchor is an installation method that does not require a PSN to be in place. The impetus for the anchor’s development was the recompletion of depleted offshore gas lift wells to PCP systems. The anchor makes this possible because it allows the gas lift system to be left in place while inserting the new anchor.
In general application, the I-PCP anchor allows I-PCPs to be run in wells that are not equipped with a PSN, or where the PSN is at the wrong location or has specifications that are unknown. The anchor system also provides an artificial-lift option to reactivate old wells without pulling the tubing.
Applying Root-Cause Failure Analysis Enhances Artificial-Lift Performance
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 17230, ’Artificial-Lift-Performance Enhancements by Applying Root-Cause Failure Analysis,’ by S.G. Lapi, SPE, and M.E. Johnson, SPE, ExxonMobil Production Company, and B. Arisman, SPE, GE Oil & Gas, prepared for the 2014 International Petroleum Technology Conference, Doha, Qatar, 20-22 January. The paper has not been peer reviewed.
This paper describes the use of a root-cause-failure-analysis (RCFA) process to improve artificial-lift- system performance in a project in Chad. The process was established with the objective of evaluating every failed pump system to determine the reason for failure, identify contributing factors, and monitor trends. The process has helped to reduce the failure frequency by more than 70% on electrical submersible pumps (ESPs) and by more than 50% on progressing-cavity pumps (PCPs), despite the fact that the ESP population has more than tripled and PCP installations have more than doubled.
Introduction
The Chad Project is in the central African country of Chad, approximately 430 km south of N’Djamena, the capital city. The vast majority of the wells are completed with 9?-in. production casing and perforated with 7-in. conveyed perforating guns at 12 shots/ft. The wells are surged to remove perforating debris and are gravel packed for sand control before the artificial-lift system is installed. Typically, ESPs are run with 4½-in. production tubing and PCP systems are conveyed with 5½-in. tubing (Fig. 1).
Formation properties are quite favorable, with permeability ranging from 0.5 to 10 darcies and porosity ranging from 24 to 28%. The hydrocarbon-bearing deposits are found at depths as shallow as 3,000 ft and as deep as 6,000 ft. The crude produced from these reservoirs has a gravity of 17 to 24°API, in addition to being heavily biodegraded and undersaturated, with viscosities ranging between 40 and 800 cp. Production is sweet, with no hydrogen sulfide or carbon dioxide, and reservoir temperature is low at 140°F.
Technology Focus: Unconventional Resources (July 2014)
Authors: Chipperfield Simon 
Published: February 2015

Technology Focus
Flowback (or cleanup) of fracturing treatments can have a profound influence on well productivity in unconventional reservoirs. The process of cleanup crosses many discipline boundaries. Given this complexity, it can be unclear who is ultimately accountable. Ensuring that someone is ultimately accountable is vital to maximizing the well results.
The most ideal form of flowback is one that maximizes production while meeting or exceeding environmental requirements.
The ideal flowback is reservoir dependent. In some reservoirs, immediate cleanup is preferential. This approach takes advantage of pressure gradients created during pumping to maximize fluid recovery (e.g., the “slowback” approach). In other reservoirs, extended shut-ins after fracture treatment can support improved productivity. In these cases, positive injection-fluid/rock interactions are encouraged and the pumped fluid may act as a form of propping agent. The challenge is in understanding what the best approach is for your environment.
Many disciplines have an effect on fracture-treatment cleanup. Reservoir and production engineers must understand the efficacy of the process by analyzing existing information such as well pressures, rates, and return-fluid composition. Completion and drilling engineers must ensure that the well trajectory and the well completion support the process of unloading fracturing fluids. Stimulation engineers must design fracturing treatments to promote cleanup. Operations engineers must manage flowback in the field to design specifications, reporting accurately and ensuring that environmental standards are met.
The ideal flowback is a virtuous cycle. The capture of fluids minimizes environmental effects. Capturing these fluids also allows them to be analyzed for fluid composition, rates, and flowback pressures, which can be used to optimize the cleanup process. The result is a cleaner environment and better-producing wells.
Achieving the perfect flowback requires multiple disciplines working in close cooperation. However, it is critical to use the talents of an individual who is capable of overseeing all facets of the process and who is ultimately accountable. Who is ultimately accountable for the fracture-treatment flowback process in your organization?
Development of Small-Molecule CO2 Thickeners
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169039, ’Development of Small-Molecule CO2 Thickeners for EOR and Fracturing,’ by J.J. Lee, S. Cummings, A. Dhuwe, R.M. Enick, and E.J. Beckman, University of Pittsburgh, and R. Perry, M. Doherty, and M. O'Brien, General Electric Global Research, prepared for the 2014 SPE Improved Oil Recovery Symposium, Tulsa, 12-16 April. The paper has not been peer reviewed.
The ideal carbon dioxide (CO2) thickener would be an affordable, safe, water-insoluble additive that could dissolve in CO2 at typical wellhead and reservoir conditions during CO2 enhanced oil recovery (EOR) and elevate the viscosity of CO2 to the same value as that of the oil. Further, the additive would not require heating or an organic cosolvent to achieve dissolution. In this paper, a strategy for designing a novel small-molecule CO2 thickener is detailed.
Introduction
Despite its longstanding success as an EOR technique, CO2 flooding does not recover all of the oil in the formation regardless of whether the reservoir has been waterflooded previously. Typically, primary recovery results in the production of approximately 5–15% of the original oil in place (OOIP), while secondary recovery is responsible for an additional 20–40% of OOIP.
The fundamental causes of this disappointingly low oil recovery can be traced to the density and viscosity of dense CO2. First, the low density of high-pressure CO2 relative to oil promotes gravity override of the CO2, reducing oil recovery in the lower portions of the formation. Second, the viscosity of dense liquid or supercritical CO2 at typical CO2- flooding conditions is approximately 0.05–0.10 cp, a value so much lower than typical oil- and brine-viscosity values that it results in an unfavorable mobility ratio. This leads to viscous fingering, which in turn leads to early CO2 breakthrough, high CO2-usage ratios, delayed CO2 production, depressed oil-production rates, and low-percent OOIP recovery. These problems can be worse when the injection well is completed in two or more producing zones.
Finding the Right Opportunities in Energy M&A
Authors: Collier Michael 
Published: February 2015

Guest editorial
One sure sign that the economy is in recovery mode is the increase in merger and acquisition (M&A) activity, including the USD 60 billion of deals in the energy sector in the first quarter of 2010. The depth and breadth of the M&A rebound in energy has been fueled by optimism that we are emerging from a global financial “funk” and we are at the beginning of a long period of sustained economic growth.
With optimism returning, there are two major reasons we may see an abundance of deals in the energy arena: pent-up demand for deals in the service and equipment space, and the new shale-gas paradigm.
Reordering of Portfolios
In the equipment and service arena, there has been a significant absence of deals over the past 2 years due to uncertain economic conditions. Companies are now in a position to acquire technology and know-how and reorder their portfolios to take advantage of their differential advantage (which is constantly in a state of flux). For example, a company with a strong presence in a particular area that is attracting a lot of investment (i.e., drilling) may seek to expand its product offering in that area to increase the share of the overall service content of the wells. In other instances, particularly in dealing with national oil companies (NOCs), service companies might seek to do a better job bundling services that are relevant to their NOC customers’ changing needs.
Several strategic moves were propelled by what appeared to be (at least at the moment) a recovering stock market, allowing senior executives to see stock-for-stock deals as fair. Thus we have seen several major stock-for-stock transactions in the service space, and (assuming the markets quickly find their way back to a stable footing) there may still be more to come.
Cash-for-stock deals, however, are less prevalent today because they depend on absolute (vs. relative) valuation fairness. Said another way, it is one thing to use my undervalued stock to acquire your undervalued stock. To your shareholders, and mine, it is a fair trade. But for me to use my cash to buy your stock, we both need to know that the valuation is not just fair on a relative scale, it has to be right. Until recently, it was difficult for both buyer and seller to see any particular acquisition price as the right price because earnings of target companies were declining. As the overall economy improves and sellers report steadily improving quarterly earnings, price expectations between buyer and seller are coming into line. When they are finally aligned, which often happens four to five quarters after the economy begins to recover, then we will see not only corporate cash-for-stock deals become common, but we will also see private equity firms come off the sidelines with a major wave of transactions.
Petrobras: A Legacy of Growth Continuing and Accelerating
Authors: Parshall Joel 
Published: February 2015

Editor’s note: This is the second in a series of profiles of leading operators, including key international and national oil companies, around the globe. The focus is on the company’s strategic direction, relationship to its government, major upstream activity, and significant technology challenges and applications.
Petrobras, Brazil’s national oil company, has become an ever-larger player among world oil producers and, with the prospects of developing the country’s huge presalt reserves, this growth in stature will not only continue but accelerate. As Petrobras President Sergio Gabrielli has noted, Brazil will soon rank among the world’s top 10 producing countries, likely rising to eighth place. A key driver of growth in the global E&P industry, the company is a catalyst of technology innovation, and an important presence in the international oil sector—not only upstream but in downstream businesses.
Established in 1953 and headquartered in Rio de Janeiro, Petrobras for decades operated as a monopoly in Brazil and was wholly owned by the Brazilian Government. That monopoly status was ended with the passage of a 1997 law establishing a competitive Brazilian oil and gas sector under national regulation. While the Government retains a controlling stock ownership in the company, approximately 40% of Petrobras voting shares today are publically traded on major stock exchanges around the world. Petrobras was ranked as the world’s fourth largest energy company at the beginning of the year by consulting group PFC Energy, and based on market capitalization, Petrobras in mid-2009 was the world’s eighth largest company, according to Ernst & Young.
Petrobras conducts business across an entire spectrum of energy sources, including fully integrated oil operations; natural-gas production and distribution; biofuels production and marketing, including ethanol and biodiesel; electric energy, including thermoelectric-, hydro-electric-, and wind-power generation; and other sources, such as solar- and hydrogen-energy technologies. Petrobras has a business presence in 28 countries.
The company earned USD 15.5 billion on USD 91.9 billion in revenue in 2009, with production averaging 2.1 million B/D of oil and 2.5 Bcf/D of natural gas. Petrobras has proven reserves of 10.3 billion bbl of oil and natural-gas liquids and 13 Tcf of natural gas.
When Petrobras began operations in the 1950s, its assets were inherited from the National Petroleum Council that had previously managed Brazil’s oil operations and consisted chiefly of two refineries and onshore fields with combined production of less than 2,700 B/D, meeting not quite 3% of domestic consumption. Onshore E&P activity successfully spread and expanded the company’s upstream operations, overcoming doubts in some geological circles that Brazil’s onshore basins could be developed technically and economically.
Energy and Environment: The Ultimate Test of E&P "Intelligence"
Authors: Kapteijn Pieter 
Published: February 2015

Management
In the next few decades, the E&P industry will face a unique confluence of two major challenges: it must continue to provide the world with sufficient oil and gas to support global development while at the same time help it reduce the environmental impact of fossil-fuel use, with a focus on the reduction of greenhouse-gas (GHG) emissions. This calls for innovative technical solutions and new approaches to the design and management of increasingly interdependent energy and CO2 value chains.
The “intelligent” capabilities that the industry has developed over the past decade can be leveraged to meet these twin challenges. The combination of CO2 enhanced oil recovery (EOR) with carbon capture and sequestration (CCS) in particular offers attractive opportunities to combine enhanced oil and gas recovery with GHG reduction, in a profitable way. This can be done at the level of individual field developments but also at the level of integrated energy/CO2 systems.
It is estimated that global CO2 emissions will have to come down to 10–11 Gt/yr by 2050 to limit the increase of average global temperatures to 2°C. This represents a reduction of 70–80% from 2009 emission levels of 29 Gt/yr. The concept of “reduction wedges,” representing 1 Gt/yr of carbon, helps put into perspective what it would require from the E&P industry to deliver a single wedge of CO2 reduction—equivalent to 3.7 Gt/yr—out of a total of eight.
Geological CO2 storage could go a long way to achieving this tar-get but the required investments in infrastructure within E&P, power generation, steel, and other industries would be huge. To illustrate the point: if the Groningen gas field in the Netherlands—the largest in western Europe—was fully utilized for CO2 sequestration, it could provide only about 1 to 2 years of storage for a single GHG reduction wedge of 3.7 Gt/yr. Worldwide, there are only 20 gas fields in the Groningen size class.
The required investments in CCS would be additional to the USD 100–150 billion/yr the E&P industry spends to maintain oil and gas production at current levels of approximately 83 million BOPD and 295 Bcf/D of gas. Another USD 300–400 billion/yr would be required to increase global production to meet a projected 1.2–1.4% annual increase in demand up to 2050.
Evaluation of the Petrophysical Properties of a Carbonate-Rich Caprock for CO2-Geological-Storage Purposes
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131525, ’Evaluation of the Petrophysical Properties of a Carbonate-Rich Caprock for CO2- Geological-Storage Purposes,’ by Nicolas Tonnet, and Daniel Broseta, SPE, University of Pau, and Gerard Mouronval, Total, prepared for the 2010 SPE EUROPEC/EAGE Annual Conference and Exhibition, Barcelona, Spain, 14-17 June. The paper has not been peer reviewed.
Before any CO2-geological-storage operation, the caprock’s ability to prevent CO2 leakage must be assessed carefully. Preventing leakage is related primarily to the caprock pore structure and to the interfacial properties of the caprock and the fluids in place, specifically the brine that imbibes into the caprock and the CO2 stored in the underlying reservoir. An experimental effort characterized some of these parameters in the carbonate-rich caprock and the reservoir conditions of a depleted gas field in France.
Introduction
The ability of the caprock to prevent leakage in a CO2-geological-storage operation must be assessed early in the planning stage in a depleted hydrocarbon reservoir or a deep saline aquifer. In the case of hydrocarbon reservoirs, the existence of a top seal (or caprock) is proven, but only with respect to hydrocarbons. In the case of deep saline aquifers, little is known about the confining properties of the overlying low-permeability layers, referred to here as caprock for simplicity.
Leakage through the caprock may occur by either mechanical or capillary failure. Both processes are caused by an overpressure in the fluid saturating the underlying reservoir. Capillary failure is considered the normal mode of caprock failure under moderate-overpressure conditions, whereas mechanical failure tends to occur for high overpressures and very tight caprocks. Mechanical failure, which includes the hydraulic or thermal generation of fractures and the reactivation of pre-existing faults, may give rise to significant leakage rates in specific zones of the subsurface. Capillary failure, however, gives rise to more pervasive and slower leakage. It occurs when pressure in the CO2 phase in the reservoir is large enough to force the CO2 into the overlying fine-grained (or low-permeability) caprock, in which the saturating brine phase is thus displaced by the intruding CO2 phase. This drainage process is controlled by the caprock pore structure and by the interfacial properties of the caprock and saturating fluids (brine and CO2).
To avoid leakage, the reservoir pressure beneath the caprock should be maintained below displacement (breakthrough) pressure, Pd, assumed here to be lower than the minimum pressure required for caprock mechanical failure. However, if the pressure is higher than Pd (but still lower than the pressure for caprock mechanical failure), leakage through the caprock is acceptable if gas (CO2) effective permeability is low enough. Effective permeabilities in the nanodarcy range or lower are considered acceptable.
Technology Focus: Subsea Technology (August 2010)
Authors: Salies Jacques B. 
Published: February 2015

Technology Focus
For several years, after the Offshore Technology Conference (OTC), I have had the opportunity to address the JPT audience and comment on subsea technologies and field applications that came to the forefront. This year, however, before getting to business, I would like to comment on the major event that hovered over OTC and the questions that could not stop being asked: “What happened?” “What consequences will the industry face?” “How should we get prepared for the day after?” I waited until the day before my review was due to put thoughts on paper. During this period, I closely followed developments and efforts to solve the catastrophe. Nevertheless, more time is necessary to cap the well and much more time will be necessary to recover the environment. How long it will take us to be back in business is another question that we all would like to answer. As we find the answer, our industry will be revisited comprehensively—from regulations and drilling procedures to equipment construction, safety, and environmental response. Time will tell.
Now, let us address subsea technology and the papers of this issue. It was pleasing to see new fields implementing subsea boosting in different parts of the world. Three fields particularly caught my attention: Perdido, Parque das Conchas, and Azurite. The Perdido field, in the ultradeepwater Gulf of Mexico, combines a spar with a subsea-boosting system—an engineering master piece. The Parque das Conchas (BC-10) field, in ultradeepwater Brazil, uses a subsea-boosting system. The Azurite field, in ultradeepwater West Africa, uses a subsea-multiphase-pumping system. Subsea boosting attests that the operators have been looking attentively into this type of solution as the technology evolves into the ultimate subsea-to-shore production systems.
I am pleased to suggest a collection of papers that addresses such solutions and their significant benefits to the field. I hope you enjoy it!
Subsea Technology additional reading available at OnePetro: www.onepetro.org
OTC 20418 • “Experiences From Operating New-Generation Riserless-Light-Well-Intervention (RLWI) Units in the North Sea, Challenges and Future Opportunities” by Robert Friedberg, Island Offshore Subsea, et al.
OTC 20619 • “Experience to Date and Future Opportunities for Subsea Processing in Statoil” by Simon Davies, Statoil, et al.
SPE 124290 • “The First All-Electric Subsea System on Stream: Development, Operational Feedback, and Benefits for Future Applications” by Pierre Gerardin, Total, et al.
OTC 20993 • “AKPO: The Subsea-Production System” by Stuart G. Nelson, Total.