bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: History Matching and Forecasting (April 2010)
Authors: Romeu Regis Kruel
Published: February 2015

Technology Focus

“Prediction is very difficult, especially of the future” (Niels Bohr, Danish Physicist, 1885–1962). Indeed, even prediction or modeling of the past is very difficult in reservoir simulation. However, as complex as it is, history matching for model calibration generally is required to generate convincing forecasts. Fortunately, more-productive and -consistent methods are moving from research to application.

The traditional trial-and-error approach for history matching usually is disappointing: too time-consuming and ineffective at the end, depending on the objectives. Consider a reservoir-simulation model calibrated by the usual not-so-bad/not-so-good history matching (easier to consider than to do), and its use for short-term and long-term forecasting. Despite all of the built-in physics, numerical algorithms, geology characterization, etc., the short-term forecast from this model may be worse than just assuming that each well will repeat its current water-cut data next month. This result is because recent production data were only loosely assimilated into the model, whereas these data are of first-order importance to predict next month’s production. For long-term prediction, we notice that standard workflows generally are not good for coupling uncertainty analysis with history matching. A large and representative sample of possible scenarios should be explored to obtain robust long-term forecasts, but this is difficult in practice because of the lack of time, lack of imagination, or lack of method.

Modern history matching tends to be different from traditional methodology in many ways: numerical optimization instead of manual trial and error, multiple-scenario exploration instead of single-scenario exploitation, or geological consistency instead of ad hoc artifices. Three approaches have been developed with several variants and hybridization: gradient-based methods; stochastic-global-optimization methods; and—the most in vogue—data-assimilation methods, such as ensemble Kalman filter. Besides fast computers and advanced software, human-expert intervention will continue to be essential. Continued training is of uppermost importance. Keep track of the literature.

History Matching and Forecasting additional reading available at OnePetro: www.onepetro.org

SPE 119030 • “Stochastic History Matching of a Deepwater Turbidite Reservoir” by Faruk O. Alpak, SPE, Shell, et al.

SPE 125512 • “Data Assimilation Coupled to Evolutionary Algorithms—A Case Example in History Matching” by Ralf Schulze-Riegert, SPT Group, et al.

SPE 118879 • “History Matching Using a Hierarchical Stochastic Model With the Ensemble Kalman Filter: A Field Case Study” by Yanfen Zhang, University of Oklahoma, et al.
Hybrid Ensemble Kalman Filter With Coarse-Scale Constraint for Nonlinear Dynamics
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124826, ’A Hybrid Ensemble Kalman Filter With Coarse-Scale Constraint for Nonlinear Dynamics,’ by Shingo Watanabe, SPE, Akhil Datta-Gupta, SPE, and Yalchin Efendiev, SPE, Texas A&M University, and Deepak Devegowda, SPE, University of Oklahoma, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.

Interest in ensemble Kalman filters (EnKFs) is driven by the need for continuous reservoir-model updating and uncertainty assessments based on dynamic data. The EnKF approach relies on sample-based statistics derived from an ensemble of reservoir-model realizations. Sampling error in these statistics, particularly with the use of modest ensemble sizes, can degrade EnKF performance severely, leading to parameter overshoots and filter divergence. The proposed hybrid-multiscale EnKF improved operational-data assimilation and helped overcome many limitations associated with the classical EnKF implementation.  

Introduction

A primary motivation for history matching is to construct reliable predictive models and then to quantify the uncertainties in forecasting. Traditional history matching applies local and regional changes by use of multipliers to reservoir properties to calibrate the reservoir model with production data. However, this approach often creates artificial discontinuities that lessen geologic realism in the updated model. The manpower and time required to achieve a satisfactory history match render the manual process inefficient for assessing multiple-model realizations. Automated methods that use inverse theory or stochastic approaches to minimize appropriately defined misfit functions have received increased attention along with development of robust history-matching algorithms and enhancements in computational capabilities.

With modern field-monitoring technology, such as permanent well monitors and intelligent-completion technology, production data often are incorporated into the reservoir model upon availability. Recognizing under-lying uncertainties in the geologic model, it is desirable to generate a suite of plausible model realizations rather than a single best-history-matched model. The EnKF combines these capabilities for the purposes of reservoir characterization and uncertainty assessment. In the EnKF framework, an ensemble of model realizations is updated progressively as the data become available by use of an assimilation sequence that contains a forecast step that propagates the ensemble forward in time and an update step that modifies the reservoir variables to match the current observation.
Macondo Blowout Spawns a Pair of Containment Firms in Gulf of Mexico
Authors: Rassenfoss Stephen
Published: February 2015

A year after the blowout that destroyed the Deepwater Horizon platform and triggered an oil spill that lasted for months, two companies with strong ties to the effort that shut off that well are competing to be the containment firm of choice for deepwater operators in the US Gulf of Mexico (GOM)—Marine Well Containment Corporation (MWCC) and Helix Well Containment Group. In mid-February, MWCC rolled out its interim containment system built around a mix of new equipment and components used by BP last year to shut down the Macondo well. The venture was created in July 2010 by ExxonMobil with Chevron, ConocoPhillips, and Shell. In September BP joined, contributing a variety of hardware, including a manifold, flexible pipe, a riser assembly, and containment devices, including the “top hat.”

The Helix Fast Response System is built around the two vessels that became a familiar site in the aerial photos of the fleet of boats used to choke off the output from Macondo—the Q4000 which served as a production platform and the Helix Producer I that processed the crude and offloaded it to tankers.

At the end of February, Bureau of Ocean Energy Management, Regulation, and Environment (BOEMRE) issued the first deepwater drilling permit. It gave Noble Energy permission to complete a well on its Santiago prospect that it had to stop drilling in June 2010, because of the moratorium after the Macondo blowout. It named Helix as its well containment provider.

Having approved deepwater emergency response options is an essential part of getting approval for a deepwater drilling permit application. A regulation from BOEMRE—NTL 2010-N10—requires anyone who wants to drill to provide detailed information on how it could react quickly and effectively in the event of a blowout.

Compliance requires more than naming an approved provider. Documentation running more than a thousand pages long answers many of the questions that could speed emergency responses—from detailed descriptions of the well hardware to well design integrity studies intended to help answer a question that slowed the Macondo response—can the well stand up to the pressure if it is capped?

In creating their systems, both companies followed a similar approach: relying on well-established, reliable designs, components, and technology, and working closely with regulators to be sure the systems complied with their reading of the new rules.

Even after BOEMRE approves a system, operators seeking drilling permits will still need to convince regulators that the emergency response company has the capability to deal with a worst-case discharge from that well, said Ken Arnold, a member of SPE’s GOM Incident Response Task Force. The task force held a workshop with industry and academic experts to study the rule. It created a document offering guidelines based on how to estimate the dimensions of an incident “where everything in the world has to go wrong.”
Managed-Pressure Drilling To Counteract Lost-Circulation and High-Pressure-Gas Zones: South Wapiti Red Rock Field
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137428, ’Successful Use of Managed-Pressure Drilling To Counteract Lost-Circulation and High- Pressure-Gas Zones: A Case Study From the Red Rock South Wapiti Field in Grande Prairie, Alberta, Canada,’ by Hassan K. Malik, SPE, Raymond J. Litwin, SPE, and Bernard C. Jones, ConocoPhillips Canada, prepared for the 2010 Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed.

Use of heavy mud weight (MW) to control high-pressure (HP) -gas and lost-circulation zones at the same time is a challenge. The Red Rock field in the South Wapiti area in Alberta experienced this combination, which resulted in high operational costs, primarily caused by an additional casing string, high MW, and severe mud losses. On average, costs were 20% higher than anticipated, making this drilling program uneconomical.  

Introduction

The Red Rock field is in the Deep basin of western Alberta, where much of the gas is found in low-porosity, low-permeability reservoirs deposited in an epicontinental seaway. The Deep basin is unique in that porous rocks are water saturated updip to the east and gradually become gas saturated and less porous downdip to the west.

The Falher section (overlying the Gething formation) is overpressured in the area, but there is more confidence in predicting the presence on a broad scale. Coals are found throughout the Falher and Gething formations and must be considered. Historically, lost circulation has occurred in the Falher section at elevated MWs, also into several coal seams in a few cases. Recent wells have experienced kicks in the Bluesky, Gething, and Falher zones, which have driven MWs higher to manage risk. Further uphole, the Doe Creek and Dunvegan formations have been pinpointed as a main lost-circulation section in the area. Natural fractures exist in the wider area across this section, which supports the determination that these zones cause lost circulation.

Red Rock Drilling Challenges

Wells in this area are drilled with an invert-oil-based-mud (OBM) system, which is used in the field with consistent success in keeping reactive shales stable. The use of OBM systems, with high oil/water ratios, is costly in lost-circulation situations. Wellbore-strengthening materials have been used to varying degrees to mitigate losses while drilling the usual problem zones. This is seen when drilling into the Doe Creek and Dunvegan formations with low MWs (930–980 kg/m3) and losses are encountered. A regime of adding wellbore-strengthening materials before penetrating these zones helps heal the losses, and in several cases allowed the MW to be increased deeper in the well. This technique is an important tool in this area to drill through loss zones.
Technology Focus: History Matching and Forecasting (April 2011)
Authors: Cardoso Marco A.
Published: February 2015

Technology Focus

History matching and forecasting of geologically complex reservoirs are challenging aspects for efficient reservoir management. The foremost reason is the high level of uncertainty that exists in the reservoir models because of the limited, sparse, and multiscaled reservoir data available. The problem is further heightened for deepwater provinces such as the Gulf of Mexico, Brazil, and West Africa.

The objective of the history matching is to adjust the geological model and its parameters (e.g., permeabilities and porosities) such that the simulation model is able to reproduce the well-flow-rate and pressure histories reasonably. The result of the history-matching process is a new simulation model that can be very different from the original geological model. However, this history matching is an inverse problem, meaning that there is no unique solution. Different arrangements of reservoir parameters can furnish many simulation models tuned to the available past data. Even though each matched reservoir model is capable of reproducing the observed data, these various geological models can generate different production forecasts. The greatest challenge is obtaining multiple efficient history-matched models for realistic uncertainty estimation.

Conventional history matching is a trial-and-error process. The mismatch between observed and simulated values is minimized by adjusting reservoir parameters over successive simulation runs.  Even for experienced reservoir engineers, the process is very time consuming and, in general, a single adjusted scenario can be geologically inconsistent. On the other hand, modern history-matching techniques apply numerical optimization and generate multiple geologically consistent adjusted scenarios.

Most of the history-matching research work being carried out today can be classified into four types of algorithms: gradient-based methods, stochastic methods, data-assimilation approaches, and streamline techniques. Data-assimilation techniques, such as an ensemble Kalman filter, represent a very active research area, and new and potentially promising methodologies have been developed. The papers summarized in this feature and those in the additional-reading list provide good examples of new methodologies.

History Matching and Forecasting additional reading available at OnePetro: www.onepetro.org

SPE 129183 “A New Adaptively Scaled Production-Data-Integration Approach Using the Discrete Cosine Parameterization” by Eric Bhark, SPE, Texas A&M University, et al.

SPE 131627 “History Matching With Sensitivity-Based Parameter Modifications at Gridblock Level” by H. Almuallim, SPE, FirmSoft Technologies, et al.

SPE 141216 “History Matching a Field Case Using the Ensemble Kalman Filter With Covariance Localization” by Alexandre A. Emerick, SPE, Petrobras, et al.
Technology Focus: Natural Gas Processing and Handling (April 2012)
Authors: Hobbs George
Published: February 2015

Technology Focus

In 2010, natural-gas reserves were approximately equivalent to 75% of the oil reserves (including oil sands). Unconventional gas sources continue to make up an increasingly important part of the natural-gas supply, particularly shale gas and coal-bed methane (CBM), which contribute approximately 40% to US natural-gas reserves.

Generally, very remote offshore gas reserves cannot be exploited economically by use of fixed subsea pipelines that tend to link the field with a specific geographical market. Operators can maximize market reach through natural-gas liquefaction and improved marine liquefied-natural-gas (LNG) tankers. For ultimate flexibility, four floating LNG-production facilities are predicted to come on stream within this decade.

Commercial exploitation of the known massive hydrate reserves probably is some time off; however, the chemistry research involved in hydrate management for current natural-gas production may accelerate progress in that area. Hydraulic-water reuse is key to the future of the CBM and shale-gas industries.

There are many opportunities to learn about and share natural-gas technologies. An SPE workshop, “Reducing Environmental Impact of Unconventional Resources Development,” will take place in San Antonio, Texas, 23–25 April 2012. A joint SPE/SEG workshop, “Injection Induced Seismicity,” will be held in Broomfield, Colorado, 12–14 September 2012. There will be an SPE “Tight Gas” workshop in Adelaide, Australia, 10–13 June 2012, and the SPE Unconventional Reservoir Technical Interest Group (TIG) provides a useful information exchange, as does the Gas Technology TIG. The 2013 SPE Unconventional Gas Conference and Exhibition will be held in Muscat, Oman, 28–30 January. The 2013 SPE International Symposium on Oilfield Chemistry to be held in The Woodlands, Texas, 9–13 April, includes topics on gas-processing chemical applications.

Acid-gas (CO2 and H2S) removal from natural gas and sequestration/recovery/disposal technologies are very important in exploitation of poorer-quality gas finds. Much work continues in this area, and very large acid-gas-removal units are in operation or are planned for the Arabian Gulf region.

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

IPTC 15208 World’s First Demonstration Project of Natural Gas Hydrate Land Transportation by Tomonori Nogami, Mitsui Engineering and Shipbuilding, et al.

IPTC 14206 International LNG Prospects: 2011 and Beyond by Chau Tran, University of Houston, et al.

SPE 143019 Underground Natural-Gas Storage in the UK: Business Feasibility Case Study by Esther Escobar, University of Aberdeen, et al.
Improved History Matching and Uncertainty Characterization
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 141336, ’Combining the Ensemble Kalman Filter With Markov-Chain Monte Carlo for Improved History Matching and Uncertainty Characterization,’ by Alexandre A. Emerick, SPE, Petrobras, and Albert C. Reynolds, SPE, University of Tulsa, prepared for the 2011 SPE Reservoir Simulation Symposium, The Woodlands, Texas, 21-23 February. The paper has not been peer reviewed.

With the use of the ensemble Kalman filter (EnKF) for assisted history matching, the approximation of covariance matrices from a finite ensemble of states and a finite ensemble of predicted-data vectors can lead to a large underestimation of uncertainty in the posterior probability-density function (PDF) for the state vector. Regardless of whether covariance localization is used, EnKF can lead to an overestimation of the uncertainty in predictions of reservoir performance. Under reasonable assumptions, a Markov-chain Monte Carlo (MCMC) algorithm will, theoretically, generate a correct sampling of the posterior PDF conditional to dynamic data.

Introduction

In a reservoir-simulation study, history matching is essential to establish a measure of legitimacy of reservoir-performance predictions. Over the last decade, increased importance has been attached to quantifying uncertainty in reservoir-performance predictions and in reservoir description to manage risk. Because of this interest in characterizing uncertainty, it is common to generate multiple history-matched models. However, generating multiple history-matched models does not necessarily lead to a correct assessment of uncertainty. Uncertainty has no scientific meaning outside the realm of statistics and probability.

The MCMC process provides a theoretically attractive method for sampling the posterior PDF for reservoir-model parameters. MCMC does not require knowledge of the normalizing constant in the target PDF to be sampled. A properly designed MCMC method will sample the target PDF correctly in the limit as the number of states in the chain approaches infinity. However, for high-dimension problems, MCMC typically requires a large number of iterations to sample the target PDF correctly. When MCMC is used to estimate the posterior PDF of reservoir-model parameters conditional to observed production data, calculation of the probability of accepting the transition from the current state to the proposed state requires a run of the reservoir simulator to evaluate the likelihood portion of the posterior PDF. Therefore, the direct application of MCMC can be prohibitively expensive computationally for realistic reservoir cases.
In Search of Bigger, Stronger, and Lighter Ways To Open Paths for Oil Production
Authors: Rassenfoss Stephen
Published: February 2015

Proppant Advances

There’s an old line in the proppant business that customers want a product that is stronger than diamonds, lighter than water, and cheaper than dirt. And they are serious about that.

The rapid shift to unconventional oil exploration and production has made creating and maintaining better pathways for hydrocarbon flow a priority. That requires bigger bits of sand or ceramic, made stronger to maintain openings longer, and lighter, so it can be pumped further into formations using less horsepower.

Delivering larger concentrations of bigger proppant requires viscous fracturing fluids. Some of this can be described as a return to conventional formulas, but the biggest category used now in US fracturing is hybrids—a range of options being tried to increase oil yields.

With current methods often leaving more than 90% of the oil behind in unconventional formations, there’s a powerful motivation to seek out new and improved methods to ensure greater fracture conductivity.

At the SPE Hydraulic Fracturing Technology Conference in February the buzz was around a totally different approach to keeping dense particles suspended in water. Rather than putting polymer gels in water to make it more viscous, each bit of sand or ceramic is given a coating that rapidly expands in water to about 5 times its original size.

The combination, called self-suspending proppant (SSP), is far less dense than its proppant core, but this is not like putting on a life jacket. When SSP is added to water, the result looks like a murky slurry, and feels like water. This is because SSP behaves differently than untreated proppant. When SSP is in water, each grain of polymer-coated proppant expands so it has much greater volume with far less density than the grain of proppant alone. Because of its properties, SSP takes up more space in water and also makes the water appear more viscous. Also, because SSP’s density is less than that of untreated proppant—but still greater than the density of water—its settling rate is dramatically less than untreated proppant, said Robert Mahoney, vice president in charge of research and development at Soane Energy, the chemical maker developing SSP in partnership with Marathon Oil.

He describes SSP under magnification as looking like a pile of fish eggs each with a dark spot in the middle surrounded by a clear layer.

Over the next year Marathon Oil will be testing it on a series of wells to see if replacing fluid thickened by gels with individually coated particles will deliver more proppant into the formation where it can maintain flow pathways for better results.
Middle East/North Africa Region Focuses on Tight Gas
Authors: Henni Abdelghani
Published: February 2015

Conference review

As the era of the easy extraction of conventional hydrocarbon is over, energy companies across the world are tapping into difficult resources and developing unconventional reserves, such as shale gas and tight gas.

In the Middle East and North Africa region, results from recent gas exploration and appraisal activities indicate that the region holds substantial resources of unconventional gas, especially tight gas. Regardless of the existence of highly productive conventional gas fields in this region, tight gas-related exploration and appraisal activities in several countries in the region have increased and are expected to pick up pace going forward.

With this background, the SPE Middle East Unconventional Gas Conference and Exhibition (UGAS) was held in Oman to address the best practices and techniques used for the development of unconventional resources in the region. Under the theme “Unconventional and Tight Gas: Bridging the Gap for Sustainable Economic Development,” the conference highlighted the latest developments related to tight gas and shared success stories about the development of tight wells from regions all over the world. The 3-day conference highlighted the criteria, challenges, and environment required for successful unconventional gas production and how it implicates the long-term global supply of natural gas. Thirteen technical sessions along with poster and e-poster stations offered 90 presentations from more than 35 companies and 18 countries.

Delivering the keynote speech, Zaid bin Khamis al Siyabi, director general of oil and gas exploration and production at the Ministry of Oil and Gas in the Sultanate of Oman, said the Sultanate recently began searching for and exploring unconventional gas resources, and needs to make more natural gas available to local industries. “The importance of unconventional resources for the sultanate is really huge,” al Siyabi said.

Al Siyabi revealed that oil companies operating in Oman—such as Petroleum Development Oman, Shell, and BP—have drilled approximately 50 wells to explore unconventional gas resources using the latest technologies.

Darryl Willis, vice president resources, North American Gas, BP, said in his presentation titled “Development of Unconventional Resources: Past, Present and Future” that unconventional gas continues to be a journey of discovery and challenge. “The future of our industry is increasingly unconventional. In the US, about 40% of the gas comes mainly from shale gas,” Willis said.

The industry is now capable of producing gas from difficult geological structures at reasonable cost, making such resources economically viable, Willis said. “Among the success factors is the application of conventional techniques to unconventional, including the sweet-spot identification, integrated reservoir description, as well as the long-term development,” he said.
Announcement of SPE Board Nominees: 2015 SPE President and Slate of Directors
Authors: JPT staff _
Published: February 2015

SPE Board Nominations

Helge Haldorsen is the nominee for 2015 Society of Petroleum Engineers president. He and seven others make up the slate of Board nominees recommended for SPE Board positions by the society’s Nominating Committee and Board of Directors. These recommendations are based on nominations submitted via SPE’s online nominating process (see sidebar).

2015 SPE President

Helge Haldorsen is vice president–strategy and portfolio for Statoil Development and Production North America, based in Houston, Texas. He worked for Norsk Hydro in various roles, including chief reservoir engineer, vice president–technology and competence, vice president–exploration and research, senior vice president–international exploration and production, and president–Hydro Gulf of Mexico. Haldorsen has also held various engineering positions at British Petroleum, Standard Oil of Ohio (Sohio), and ExxonMobil (Esso). He was a second lieutenant in the Royal Norwegian Navy and professor of industrial mathematics at the University of Oslo.

Haldorsen earned an MS in petroleum engineering from the Norwegian Institute of Technology and a PhD in reservoir engineering from The University of Texas at Austin. He currently serves on the Offshore Technology Conference board of directors and the external advisory board for the Cockrell School of Engineering at The University of Texas at Austin.

Technical Director, Drilling and Completions

David Curry is a Baker Hughes technology fellow, based in London, UK. Prior positions with Baker Hughes include director of drill bit research and technical manager of drilling optimization. He has more than 25 years’ experience in drilling research and technology development, primarily related to drill bits and bit/rock interactions, and to drilling performance improvement. Before joining the oil industry he worked on nuclear power plant integrity.

Curry was named an SPE Distinguished Member in 2010. He is chair of SPE’s Research and Development (R&D) Advisory Committee, past chair of SPE’s R&D Technical Section, and has served on SPE’s Drilling and Completions Advisory Committee, Drilling and Completions Award Committee, and Books Development Committee. He was executive editor of SPE Drilling and Completion, and in 2007 was named A Peer Apart for peer reviewing more than 100 SPE papers. Curry has published more than 40 papers, been awarded eight patents, and coauthored one book. He earned an MA in natural sciences and a PhD in fracture mechanics, both at the University of Cambridge, and is a chartered engineer in the UK.
Advancing Industry Technology: A New Ecosystem for Innovation
Authors: Karanjikar Mukund , Pike William , Chitta Dolly
Published: February 2015

Management

Over the past several decades, the upstream oil and gas industry has developed into a three-way structure consisting of operating companies, national oil companies, and service companies. In the absence of a major market need, such a triangular structure worked well enough to keep the industry functioning. As developing economies in countries such as China, India, and Brazil started to become major petroleum consumers in the early 2000s, crude oil prices began to skyrocket. The global oil supply and demand situation remains relatively tight (Fig. 1). Even today, the industry can barely meet peak demand of 90 million BOPD. The triangular structure now falls short of meeting market needs.

A large part of the problem is that all the easily available oil has been found and much has been depleted. Growth potential now is in unconventional oil, Arctic resources, and improved recovery factors in mature areas. Development of these petroleum resources requires innovative and cost-effective technologies. These technologies must also be safe and environmentally benign. While many of them are being, and will be, developed by the upstream industry, many more can, and should, leverage technological advances taking place in other industries. Technology transfer from other industries is not a new phenomenon. From time to time, the upstream industry has benefited from innovations in adjacent markets such as the military, medical, optics, and information technology sectors. For example, military technology developed during World War II played a large part in modernizing the upstream industry in the 1950s and later years.

Some of the innovations that migrated from military technology include shaped charges, gravity-based structures, and reeled pipelines and umbilicals. Shaped charges were adopted by the industry for use in tubular perforation and separation. Towed by the Allied forces from Britain, concrete gravity-based structures were flooded in place off the coast of France to serve as breakwaters during the Invasion of Normandy. Later, similar structures were used in the design of offshore oil production facilities. Reeled pipelines and umbilicals, used to supply fuel across the English Channel to Allied troops landing in Normandy, became the basis for the coiled tubing and umbilical techniques now used in oil-field operations.

More recently, nuclear magnetic resonance and digital core analysis developed in the medical and chemical fields respectively, have fostered technological advances in exploration and production. However, as significant as past technology transfer has been, it has occurred haphazardly. What is now needed is a more aggressive, organized system for the transfer of external technology into our industry. To create the ecosystem necessary to accomplish this, we first must honestly address a number of issues that impede technology transfer.
Taking a Fresh View of Riser Margin for Deepwater Wells Potentially Boosts Safety
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22889, ’A Step Change in Safety: Drilling Deepwater Wells With Riser Margin,’ by Robert Ziegler, SPE, Petronas, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

Riser margins were abandoned when fluid columns in risers became too long with increasing water depth accessed when floating drilling units with subsea blowout preventers (BOPs) moved to deep water. Removing risers in disconnect events means wells go underbalanced and rely on BOPs to contain wellbore pressure. With the advent of a simple retrofit dual-gradient system based on partially evacuating the riser by pumping mud returns back to surface from an outlet in the riser, riser margin in the form of an overbalanced well can be reintroduced in many cases.

Setting the Scene

Deepwater drilling has a multitude of unique challenges.

Water depth: Cold temperatures combine with long fluid columns with high pressures at the seabed most often sitting squarely in the hydrate-formation zone. Ocean forces put mechanical stresses on the riser system. Perhaps most challenging, a highly complex hydraulic system, the subsea BOP, must be operated remotely in a very hostile environment.

Deepwater depositional environment: This leads in most cases to a very tight margin between formation strength and pore pressure.

Existing emergency procedures: In the case of a loss of position of the rig, a complex sequence of disconnecting from the BOP must be initiated. The BOP also needs to be closed before the lower marine riser package is disconnected and must reliably seal the wellbore because, by removing the riser, the well becomes underbalanced because primary well control by mud weight is lost.

Status Quo

The solutions that the industry has embarked on to address these challenges have often been overly complex evolutionary developments instead of clean-sheet designs, leading to high costs and an unavoidable increase of mechanical failure modes. The best example for this approach is the current generation of subsea BOPs. In their functionality, these devices remain close to the original patent in 1929; but, today, they are very large, complex, and heavy (350 tons) devices that require an enormous amount of maintenance and testing.

Even if a BOP is closed on an inflow in time so the flow is entirely contained below the BOP, circulating out this kick by an established “driller’s method” very often proves to be difficult if not impossible. This is mainly related to two factors. One is the risk of hydrate formation. The moment gas and free water are mixed in the BOP area, hydrates will form. The second factor is the narrow margin between fracture gradient and pore pressure. Very often, the formation is not able to support the backpressure created by the choke line friction, and circulation without losses can never be established.
Technology Focus: High-Pressure/High-Temperature Challenges (April 2013)
Authors: Payne Mike
Published: February 2015

Technology Focus

High-pressure/high-temperature (HP/HT) operations are projected to double in well count over the next 6 years. In addition to this steady increase in activity, the conditions in these extreme wells will also become more severe as well depths, pressures, and temperatures also trend higher.

In the Norwegian sector of the North Sea, one of the most extreme HP/HT wells in that region has been drilled. As a means of addressing the challenges posed by tight pore-pressure/fracture-gradient windows, managed-pressure-drilling (MPD) technologies were applied to minimize the effects of pressure fluctuations that occur in standard drilling. The MPD technology, the so-called “backpressure” technique, uses the controlled application of surface backpressure when mud circulation stops to replace the incremental equivalent-circulating-density effects present when mud circulation is active. In addition to precise management of the pressure profiles imposed on the formations, this active circulation and pressurization technology increases the accuracy with which unwanted influxes can be detected. Influxes as small as 0.25 bbl can be identified, thereby improving kick-detection capability.

In south Louisiana, the largest onshore drilling rig in the world has been drilling the deepest well ever drilled in that state, an accolade that is impressive given the long heritage that Louisiana boasts with regard to HP/HT wells. Several operators are active in this area, with a new state depth record being set by one well reaching a depth of 25,500 ft. Another HP/HT prospect in this area is permitted for a total depth of 29,000 ft. In another part of the world, Malaysia, operators are planning ultra- HP/HT operations with bottomhole static temperatures above 430°F. This includes more than a dozen prospects in peninsular and east Malaysia. This region may prove to be one of the most active areas for HP/HT operations in the near future.

HP/HT drilling and completions require careful planning, attention to detail, robust testing and qualification programs, strong quality control, and thorough contingency planning. The ongoing industry successes addressing HP/HT challenges globally are testament to the focus that our industry brings to bear as these challenges are met and addressed.

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

SPE 158851 Testing and Perforating in the HP/HT Deepwater and Ultradeepwater Environment by Curtis Wendler, Halliburton, et al.

SPE 154768 Developing Novel Wellbore-Heat-Transfer Strategies for HP/HT Wells by Mohd Amin Shoushtari, Universiti Teknologi Petronas, et al.

SPE/IADC 163557 Annular-Pressure-Buildup Analysis and Methodology With Examples From Multifrac Horizontal Wells and HP/HT Reservoirs by Jonathan Bellarby, Canmore Consulting, et al.
Design Advances of Ultra-HP/HT Completion and Production Tools
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166231, ’Design Verification, Optimization, and Validation of Ultra-HP/HT Completion and Production Tools,’ by Guijun Deng, James Doane, Antonio Ruffo, SPE, Goang-Ding Shyu, and Scott Collins, SPE, Baker Hughes, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September- 2 October. The paper has not been peer reviewed.

Ultra-high-pressure/high-temperature (HP/HT) wells are currently being drilled in the Gulf of Mexico on the shelf and in deep water. Many of these wells have a total depth in excess of 30,000 ft, where reservoir pressures and temperatures approach 30,000 psi and 500°F, respectively. There are currently few packer-type devices that are considered fit for service in these applications. This paper gives an overview of the latest developments in how advanced finite-element- analysis (FEA) tools are used to verify, optimize, and validate ultra- HP/HT completion and production tools.

Introduction

The classification of HP/HT reservoirs has varied over time. In the past, HP/HT fields were attributed to any condition of greater than 10,000-psi pressure and greater than 300°F temperature. But over the last 20 years, equipment has become widely available for pressures below 15,000 psi and temperatures lower than 350°F; therefore, those fields were no longer classified as HP/HT fields. HP/HT conditions were defined as having pressures between 15,000 and 20,000 psi and temperatures between 350 and 450°F. Ultra-HP/HT conditions were defined as having pressures between 20,000 and 35,000 psi and temperatures between 450 and 550°F. Fig. 1 is the visual representation of the latest HP/HT designations, which were reached by common agreement among oil operators and service companies.

There are several technological challenges that must be overcome for downhole service and completion tools to operate successfully in the ultra- HP/HT environment.
Comments (May 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Analytical Tools Optimize Unbonded Flexible Pipes for Deepwater Environments
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 15169, "Stateof- the-Art Analytical Tools Improve Optimization of Unbonded Flexible Pipes for Deepwater Environments," by Y. Zhang, B. Chen, L. Qiu, T. Hill, and M. Case, Halliburton Wellstream, prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Dynamic Simulator Predicts Gas Lift Well Instability
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84917, "Gas Lift Instability Resulted Production Loss and Its Remedy by Feedback Control: Dynamical Simulation Results," by Bin Hu and Michael Golan, SPE, Norwegian U. of Science and Technology, prepared for the 2003 SPE International Improved Oil Recovery Conference, Kuala Lumpur, 20-21 October.
New Approach for Modeling Progressing-Cavity-Pump Performance
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84137, "New Approach for Modeling Progressive- Cavity-Pumps Performance," by Jose Gamboa and Aurelio Olivet, GD Solutions C.A., and Sorelys Espin, SPE, U. Simon Bolivar, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Digital Core Laboratory: Reservoir-Core Properties Derived From 3D Images
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 87009, "Digital Core Laboratory: Properties of Reservoir Core Derived From 3D Images," by M.A. Knackstedt, SPE, Australian Natl. U., U. of New South Wales; C.H. Arns, SPE, A. Limaye, A. Sakellariou, T.J. Senden, and A.P. Sheppard, Australian Natl. U.; R.M. Sok, Australian Natl. U., U. of New South Wales; W.V. Pinczewski, SPE, U. of New South Wales; and G.F. Bunn, SPE, BHP Billiton Petroleum, prepared for the 2004 SPE Asia Pacific Conference on Integrated Modelling for Asset Management, Kuala Lumpur, 29-30 March.
Holistic Project Planning: How Work-Force Development Impacts Business Results
Authors: Grimsley Jim
Published: February 2015

E&P companies that are trying to meet growing energy demand know that prudent exploitation and replacement of their asset base is critical to long-term success. Supermajors and independents are increasingly depending on an asset base that is characterized by multiyear, multibillion-dollar projects in remote, developing, and technically challenging environments. The planning, construction, operation, and maintenance of these assets, such as deepwater platforms and liquefied natural gas facilities, require holistic project planning and superior execution.

A key component of holistic project planning in the frontier areas that in the past has been often underestimated is work-force development. But companies that take a disciplined approach in this area achieve:

- Improved alignment with the host government.

- Lower operating costs.

- Higher return on their investment.

So, how does work-force development fit into a holistic project plan? What is it, and how does it deliver business results?

A New Opportunity

Holistic project planning synchronizes the various asset development, operating, and work-force strategies to optimize each phase of the asset life cycle. Over the past several years, both through experience and because of the size of the investments as well as the production-deferral implications, operators have become increasingly proficient and focused on planning and executing the development of assets in frontier markets. Project management, risk management, supply chain, and logistics processes are being adapted to the challenges presented by frontier development. As projects have grown into the multibillion-dollar range, the work-force development strategy represents an increasing area of risk and opportunity.

The strategy traditionally used by operators relied heavily on expatriates. But times have changed, and operators are facing aggressive local content targets. Using a national work force is no longer an option; it is a requirement.

It is also a major challenge. The national work force in frontier markets oftentimes does not have the technical capabilities and management skills required to operate and support today’s increasingly complex oil and gas operations. Operators must determine how the national work force can be developed effectively to sustain their operations.
Overview: Formation Evaluation (May 2005)
Authors: Unalmiser Servet
Published: February 2015

A new generation of downhole intelligent systems has made real-time reservoir evaluation the new norm in the industry. Advances in formation-evaluation tools, such as the modern capture and near-infrared spectroscopy tools, allowing more-accurate determination of petrophysical data and in-situ fluid composition, have matched the growing sophistication in geosteering and well placement through improved measurement-while-drilling and logging-while-drilling technologies. The emerging real-time character of formation evaluation brings along a host of new challenges for the industry. We need to ponder the answers to questions such as the following.

- How do we manage the enormous growth in the volume of data?

- How do we convert the extra data to higher-accuracy reservoir characterization?

Fuzzy logic and neural networks may point to potential pathways. Another noteworthy evolution is occurring in the area of formation imaging. Spanning across many scales, ranging from the pore throat to the wellbore, new dual-energy computer-tomography-scanning and nuclear-magnetic-resonance mapping techniques enable us to peer inside the rock to get a better understanding of multiphase-flow experiments. Wells with vastly complex subsurface architectures give us the ability to image reservoirs (e.g., fractures, boundaries, and orientation frequency) in greater detail than ever before. In short, formation evaluation is getting better and smarter.

Additional Formation Evaluation Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 88688 Image Enhancement, Automated Interpretation, and 3D Visualization of Borehole-Image Logs in Characterization and Calibration of Fractures in Kuwait

SPE 88636 Design Considerations for a New High-Data-Rate LWD Acoustic Telemetry System

SPE 88519 A Case Study of Carbon-Oxygen Logging Through Multiple Tubular Strings Offshore Indonesia: Reservoir-Model Verification With Emphasis on Fluid Contact and Bypass Oil Identification

SPE 91607 Damage Interpretation of Properly and Improperly Drilled Underbalanced Horizontals in the Fractured Jean Marie Reservoir Using Novel Modeling and Methodology