bluuebunny/crossref_metadata_2025 huggingface dataset:
2013 OTC Mirrors Current Industry Vitality
Authors: Parshall Joel
Published: February 2015

Conference Review

This year’s Offshore Technology Conference (OTC), held 6-9 May in Houston, reflected the offshore oil sector’s health and energy, with attendance hitting a 30-year high and the event attracting top industry names from around the world. The globe’s largest offshore industry event attracted 104,800 people, the second highest in show history and up 17% from last year. Exhibitors represented 40 countries.

Panel sessions, keynote speeches, and technical papers spanned the breadth and depth of the oil and gas industry.

At one panel session, energy ministers and national oil company senior executives shared their perspectives on how the industry should adjust to address energy challenges as well as how the role of companies and governments should change to shape the future. The panel was moderated by Gamal Hassan, chief executive officer of ADHIG and OTC Program Chairman.

The panel began with Jose de Vasconcelos, Angola’s Minister of Petroleum, who highlighted the connection between the need for energy and economic and social development. The industry faces many challenges in the quest to obtain energy security, which he defines as an equilibrium between supply and demand. Several challenges must be addressed to meet production needs: technologic, environmental, regulatory, and financial. Angola, he said, will maintain a permanent dialog with other producers to develop a common approach on energy and energy-related issues.

David Ramsay, Minister of Industry, Tourism, and Investment, Northwest Territories, Canada, said that the role of government is to ensure that resources are “developed in a manner that brings economic development while ensuring the environment and its benefits” and at the same time working with industry and regulatory agencies to achieve this. Ramsay said that there is a renewed interest in the Arctic and northern Canada with opportunities onshore and offshore. The Canadian government is building infrastructure to assist in the transportation of fuels.

Petrobras Chief Executive Officer Maria das Gracas Silva Foster said that exploration is a priority, and major investments that have been sustained over several years have resulted in the development of a diversified and competitive goods and services. Petrobras has benefited from a close association with universities to facilitate research in exploration and development, and the recent major discoveries as well as monetization of these reserves are a direct result of the investments in research and universities.
Technology Focus: Reservoir Simulation (July 2013)
Authors: Crick Martin
Published: February 2015

Technology Focus

Looking back through previous editions of this article, I note that, in 2011, I wrote, “there’s a growing tendency in some quarters to use very simple models.” That may be true, but there is also a growing tendency among vendors to offer models with more and more features. That is how they stay in business, after all, and many of the new features solve problems we have struggled with for years. The trouble, however, is sometimes a feeling that all those features have to be used at the same time.

Let’s remind ourselves that a compositional model will never have as many components as there are distinct molecules in the reservoir fluid. The most sophisticated coupled pipeline simulator is still only an approximation of the complexity of fluid flow in pipes. Even the most advanced geomechanics simulator has a very coarse model of the over-, under- and sideburdens, and a crude approximation of often unknown boundary conditions. Building an exact model of the reservoir and production system is like seeking the end of the rainbow.

Piling on complex features can easily mask critical issues. We should always strive to use the simplest model that captures the most important physics affecting the decision we are trying to make. And judging what is “the most important” physics is the responsibility of the reservoir engineer, not the software and not the software vendor. A simulation model is only a model. And our job is to produce the reservoir, not the model.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 159274 A Novel Simulation-Model Review Process by M.R. Palke, Ryder Scott Company, et al.

SPE 159584 Dual-Continuum Modeling of Shale and Tight Gas Reservoirs by Prince N. Azom, The University of Texas at Austin, et al.

SPE 162380 Application of Streamline Simulation to Reservoir Management: Management of WAG-Injection Optimization by Mohamed Bouaouaja, Schlumberger, et al.

SPE 162045 Stochastic Uncertainty Analysis in Compositional Simulation for Giant-Gas/Condensate-Field Reservoir-Performance Prediction by E. Descubes, Schlumberger, et al.

SPE 164142 Uncertainty-Quantification Workflow for Mature Oil Fields: Combining Experimental-Design Techniques and Different Response-Surface Models by Syed Jawwad Ahmed, ADNOC, et al.
Massively Parallel Simulation of Oceanic-Gas-Hydrate Production
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 17026, ’Massively Parallel Simulation of Production From Oceanic- Gas-Hydrate Deposits,’ by Matthew T. Reagan, SPE, George J. Moridis, SPE, Craig M. Freeman, SPE, Katie L. Boyle, and Noel D. Keen, Lawrence Berkeley National Laboratory, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

Large volumes of gas can be produced at high rates with conventional horizontal- or vertical-well configurations for long periods of time from some methane-hydrate accumulations by means of depressurization-induced dissociation. However, most assessments of hydrate production use simplified or reduced-scale 3D or 2D production simulations. This study used a message-passing-interface parallel code to make the first field-scale assessment of a large deep-ocean hydrate reservoir. Systems of up to 2.5 million gridblocks, running on thousands of supercomputing nodes, were required to simulate such a large system at the highest level of detail. The simulations begin to reveal the challenges inherent in producing from deep relatively cold systems with extensive water-bearing channels and connectivity to large aquifers. The main difficulties are water production and achieving depressurization.

Introduction

Gas hydrates are solid crystalline com-pounds in which gas molecules occupy the lattices of ice-like crystal structures called hosts. Gas hydrates occur in the permafrost and in deep-ocean sediments, where the necessary conditions of low temperature and high pressure exist for their formation and stability. Most naturally occurring gas hydrates contain methane in abundance. Not all hydrates are desirable targets for production. Of the three possible methods of hydrate dissociation for gas production—depressurization, thermal stimulation, and use of inhibitors—depressurization appears to be the most efficient. Recent studies have indicated that, under certain conditions, gas can be produced from natural hydrate deposits at high rates over long periods of time by use of conventional technology. Earlier work focused on production from vertical wells, but more-recent studies show that horizontal wells are more productive and are easier to manage, if the technology is available.

Study

The objective of this study was to use real geophysical data at the field scale to simulate a realistic 3D gas-hydrate reservoir. Previous studies focused on simple 2D modeling, 2D modeling with artificial heterogeneity, or extremely simplified (coarse-scale) 3D modeling. Through collaboration, Statoil provided real data on the geometry and geology of a known oceanic-hydrate system. The deposit is a layered system, approximately 7×5.5 km and 350 m thick. The hydrate is arranged in a series of high-permeability channels bounded by slightly-lower-permeability levees. The system is probably impermeable at the top and bottom boundaries, but may connect to an aquifer along the x–z face.
Technology Focus: Unconventional Resources (July 2013)
Authors: Chipperfield Simon
Published: February 2015

Technology Focus

Unconventional gas is poised to enter its Golden Age and to effect positive global change if it can meet three challenges.

Consider the 7 billion people on Earth who use energy each day. Consider the World Health Organization statistic that 3% of all world health issues are related to indoor burning of fossil fuels. Consider the potential effects of global warming and the fact that gas emits less greenhouse gas than coal, currently the most prevalent energy source. As you consider this global perspective, you will recognize the biggest driver of energy demand—namely, the human desire to sustain and improve the well-being of ourselves, our families, and our communities. You will also notice the positive effect gas can have.

Through 2040, we will see enormous population and economic growth that will increase energy demand by more than 40%, according to an ExxonMobil study, with gas projected to surpass coal demand in the next decade.

Gas-driven changes have already begun. In fact, the use of gas instead of coal in the power-generation sector is already helping slow global carbon dioxide emissions, and, in the United States and other developed economies, emissions are actually falling.

Again, unconventional gas will drive further transformation if we can overcome three critical challenges.

The first is our ability to deliver the technologies necessary to unlock the vast global unconventional gas potential of more than 14,000 Tcf. For example, horizontal, hydraulically fractured wells have been a key to unlocking the shale potential in North America, but are they the ideal technology in other parts of the world, and are they ideal for coal and tight gas?

The second is our ability to deliver a cost-effective, reliable, and timely energy option for the world. For upstream engineers and geoscientists, cost-effective, efficient delivery includes the development of smart, streamlined factory processes and technologies in the field and office throughout the appraisal and development phases.

The third challenge is our demonstration of social responsibility, measured by the public. This will be based on our capability to leave the environment better than we found it, by providing jobs, supporting local investment, and maintaining the highest environmental standards.

If we can deliver in these three areas, the Golden Age of unconventional gas will occur and make a better world.

And I am confident that we will.

Recommended additional reading at OnePetro: www.onepetro.org.

IPTC 16608 Integrating an LNG Plant With an Unconventional Gas Supply by Chris Langley, Arrow Energy, et al.

SPE 162777 What Don’t We Know About Self-Sourced Oil Reservoirs: Challenges and Potential Solutions by Steve Larter, University of Calgary, et al.

SPE 163987 Optimizing Remote Unconventional Gas Exploration by Martin Rylance, BP

SPE 149872 Stimulation Unlocks Coalbed Methane: Lessons Learned in India by Shahvir Pooniwala, Baker Hughes
Liner-Based Stimulation Technology Without Fracturing Proven in Field
Authors: Jorgensen Thomas
Published: February 2015

Technology Update

Efficient production in many fields requires reservoir stimulation. Some of the challenges with hydraulic fracture stimulation are reservoir-related, such as consistently stimulating all targeted intervals. The growth of hydraulic fractures in the vertical direction is difficult to predict, leading to the risk for entering unsought gas- or water-bearing formations. Operations can be complex, costly, and pose environmental challenges.

A new liner-based stimulation technology has been developed and field tested by Fishbones to be simple, efficient, and more controllable with less environmental impact. The method uses less fluid and reduces greatly the risk of groundwater contamination and the disposal of recovered stimulation fluid. Field experience has shown positive productivity response, with an 8.3 times increase in 30-day cumulative initial production (IP-30) in an existing well in a tight limestone formation. The productivity index was increased by 30 times.

The liner-based stimulation technology was originally developed for carbonate reservoirs, but is also applicable in coalbed methane and unconsolidated formations. Technology suitable for sandstones and other clastic formations is being developed.

Technology Description

The technology uses a liner sub that houses four small-diameter, high-strength tubes called needles, each with a jet nozzle on the end (Fig. 1). The sub is made up to a full-length casing joint and needle assemblies up to 40 ft long are assembled in the workshop before the sub is sent to the field.

The subs are run as integral parts of the liner in the open hole and are positioned across the formation where stimulation is desired. The needles are located inside the sub/liner joints while the sub is run in hole. The liner is hung off with a standard liner hanger.

In a carbonate formation, a basic hydrochloric acid (HCl) fluid system is pumped. The fluid jets out of the nozzles, and the formation ahead of the tubes is jetted away by a combination of erosion and acid chemical dissolution. Differential pressure across the liner drives the needles into the formation, and they penetrate the rock until fully extended. Typical jetting pressure is 3,000 psi.

All laterals are created simultaneously in a short pumping job, resulting in a fishbone-style well completion with multiple laterals extending from the main bore (Fig. 2). The rate of penetration depends on the formation composition, porosity, downhole temperatures, nozzle configuration, jetting fluid, and jetting pressures. The needles exit the sub at an approximate 40° angle. The bending through the exit port results in laterals with an approximate 90° angle relative to the wellbore.
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.
Techbits: Report of the SPE Gulf of Mexico Deepwater Drilling and Completions Advisory Summit
Authors: JPT staff _
Published: February 2015

Techbits

On 17–18 March 2011, SPE sponsored a two-day summit to answer questions proposed by a US National Academy of Engineering/National Research Council (NAE/NRC) panel examining US Gulf of Mexico deepwater operations. The NAE/NRC committee, which has been asked by the US Secretary of the Interior to identify ways of reducing the risk of incidents similar to the Macondo well blowout from occurring in the future, prepared a list of questions for consideration by the summit participants.

This SPE Technology Summit, titled “Gulf of Mexico Deepwater Drilling and Completions Advisory Summit to NAE/NRC Committee,” was attended by oil and gas industry professionals from operating companies, service companies, consulting companies, and academia. The participants were accepted based on their industry experience, and were explicitly asked to contribute their own views as engineers, not as advocates for their organizations.

Summit participants met in five breakout groups and as a whole to discuss the questions. The following are excerpts from the report, organized by session topic. The complete report is available online at www.spe.org/industry/hse.

Section 1: Oversight

What are the potential values and feasibilities of using a separate path of reporting and oversight for cost and schedule versus decisions affecting the integrity and safety of the well?

Summit participants do not believe there is value in using a separate path of reporting and oversight. Safety cannot be separated from operational decisions. Good safety practices and good business practices (including cost and schedule) go hand in hand. The industry has reduced occupational injuries in the past by integrating operations and safety reporting and oversight. Further improvements can be made in well integrity and process safety by applying similar integration principles.

To what extent should the oversight be performed by the companies, independent third parties (e.g., classification societies), or regulators?

All three parties need to be involved in various levels of oversight. Company oversight should include a quality assurance process. The company is ultimately responsible for its safe operations. Independent third parties (both external and internal) have a role in providing specific expertise, broader industry perspective, and objectivity. Government regulators have a critical role in ensuring that all parties meet compliance obligations.
Connecting R&D with the Goals of E&P
Authors: Rassenfoss Stephen
Published: February 2015

When researchers gathered for the SPE 2011 Research & Development Symposium in June, the topics ranged from the tiniest particle to the biggest oil fields, with an underlying theme of effectively managing an unpredictable process.

During the three-day meeting in Austin, Texas, there were some common themes, including the importance of making long-term commitments, reaching out to original thinkers, encouraging collaboration, developing the next generation of talent, and focusing on the goals of the enterprise.

Petrobras’ broad research program is focused on developing the country’s rich reserves, which present many technical challenges, and a research center it hopes will remain after the oil boom has passed. “Through these technologies, we are targeting a step change in how we explore and produce oil and gas, and a step change in how these technologies are developed,” said Carlos Tadeu Da Costa Fraga, executive manager of research and development center at Petrobras.

In the keynote address, Scott Tinker, director of the Bureau of Economic Geology at the University of Texas at Austin, offered a detailed discussion of what it takes to create and run an industry-supported energy research program.

The speech described the creation and operation of the Advanced Energy Consortium (AEC), where Tinker is also director. Its goal is to discover something as useful as seismic or well logging, and so small it can be measured in nanometers. Bringing together 10 companies to fund the consortium, top research talent, and the legal and institutional framework took about four years before the research could begin.

The operation of the AEC is built on a high level of interaction with researchers at 25 institutions around the world. Every other month, it holds an update meeting on each of the 30 projects. Once a year, a decision is made on whether to continue, wind down or redirect each of the projects.

“There is a lot more oversight Tinker than the researchers are used to,” said Tinker. “Most have come to appreciate the feedback and interaction when faced with difficulties, and they understand that some research ideas are not working out.”

Each year about 20 percent of the projects are phased out, and another 20 percent are asked to go in another direction. “Any time you kill a project, it is hard,” said Tinker. He added that when it comes to research, generally, there is a need for more critical thinking about what is the best use of resources.
Australia's Quiet Success Story: The Riches of Bass Strait
Authors: Beckwith Robin
Published: February 2015

Major liquefied natural gas (LNG) developments tend to grab Australian energy headlines, with Shell’s Prelude floating LNG, Chevron’s Gorgon and Wheatstone, Woodside’s Pluto, Santos’ Gladstone, ConocoPhilips’ Darwin, and Inpex’s Ichthys projects prominent among them. However, to be a net exporter of natural gas—currently the world’s fourth largest (after Qatar, Malaysia, and Indonesia) on course to achieve status as the second largest possibly by 2020—Australia must first meet the needs of its own population. With a vast area of 7.75 million sq km, whose cities tend to hug the nation’s 25,760 km coastline, the country faces continual economic challenge to be efficient in delivering both oil and gas to its 21.8 million people. Playing a critical role in such delivery are the oil and gas riches first identified in 1965 in the hostile waters of Bass Strait.

Throughout the 42 years following first oil and gas production, Bass Strait has served Australia’s economy as the source of almost two-thirds of its oil and approximately 30% of its gas. The rock underlying its relatively shallow but notoriously rough waters continues to yield resources, with several projects—the largest being the Esso-BHP Billiton joint venture’s Kipper Tuna Turrum Project and Origin Energy’s BassGas Project—extending natural gas and liquid hydrocarbon supplies to Australia’s southeastern states of Victoria, Tasmania, and New South Wales for several decades, well beyond the strait’s originally projected 35-year life span.

The AUD 4.4 billion Kipper Tuna Turrum Project in the offshore Gippsland Basin is currently under development, with pipelines, subsea equipment, and jackets installed throughout this year, and final infrastructure installation, tie-in activities, and start-up due in 2012–2013. Operational since mid-2006, the BassGas Project, at an estimated cost of AUD 750 million, centers on the Yolla field in the Bass Basin, in waters administered by Tasmania.

The Flow of History

In 1798–1799, surgeon and explorer George Bass traveled through and delineated the strait subsequently named after him. Two hundred and thirteen years later, Australia’s Bass Strait reached the 46th anniversary of another discovery: natural gas from its first well, the Barracouta I, drilled by the Glomar III, which withstood the brunt of the strait’s legendary hostile waters to find the resources. Since 1969, the channel of water—which lies between the state of Victoria, to the north on the mainland, and the island state of Tasmania to the south, and between the Indian Ocean to the west and the Tasman Sea to the east—has yielded more than 4 billion bbl of crude oil and more than 7 Tcf of natural gas.
Navigating the Gulf of Mexico Hurricane Season: Past Lessons and a Path Forward
Authors: Braswell Gentry
Published: February 2015

In a body of water commonly traveled by powerful cyclones during hurricane season, weather challenges in the US Gulf of Mexico (GOM) must be met with equally formidable technology.

Such technology includes the dynamic positioning of vessels and disconnectible transfer systems; streamlined evacuation, abandonment, and plugging procedures; platform mooring, floaters, and risers; rig and module tie down; post-storm structural inspection; and weather-savvy structure design.

Integrity Performance and Data

The GOM platform design criteria have become more stringent following the major storms of the past several years. The impact of these storms on oilfield infrastructure has been greater on the GOM continental shelf, where development began in 1947, than on deepwater regions where facilities’ installation began in 1995.

Today, shelf development is in decline and deepwater infrastructure is fundamentally different, said Mohammad Rahman, lead analyst for the Gulf of Mexico at Wood Mackenzie. Deepwater platforms are too deep for platform jackets and rely instead on mooring cables for which weather design specifications regarding strength and number have recently become stricter, he said.

For example, regarding the comparison of fiber rope mooring systems’ performance testing methods, modeling with Young’s Modulus by Cross Sectional Area with an upper- and lower-bound linear fiber rope stiffness model, compared with modeling the true nonlinear stiffness behavior exhibited by fiber ropes, was presented in paper OTC 20838-MS, “Fiber Rope Mooring Assessment-API RP 2SM Piecewise Linear Stiffness Vs. Nonlinear Stiffness With Integrated Permanent Rope Elongation (E.H. Zimmerman, Delmar Systems, et al, 2010).” The latter nonlinear method also incorporates a function to capture permanent or nonrecoverable rope elongation caused by a hurricane, and its impact on the performance of a mooring system.

“By modeling the true nonlinear stiff-ness and being able to capture the permanent nonrecoverable elongation of fiber mooring ropes in a mooring analysis, the designer can more accurately assess the vessel motions during a storm event and more effectively plan component lengths such that retensioning operations will not significantly impact the facility’s ability to operate,” the paper said.