bluuebunny/crossref_metadata_2025 huggingface dataset:
Cuttings Transport With Foam Under Simulated Downhole Horizontal Conditions
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 99201, "Experimental Study on Cuttings Transport With Foam Under Simulated Horizontal Downhole Conditions," by Z. Chen, SPE, R.M. Ahmed, SPE, S.Z. Miska, SPE, N.E. Takach, SPE, M. Yu, SPE, and M.B. Pickell, U. of Tulsa, and J. Hallman, SPE, Weatherford Intl. Ltd., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February.

The use of drilling foams is increasing because foams exhibit properties that are desirable in many drilling operations. A good knowledge of cuttings-transport efficiency under downhole conditions is essential for safe foam drilling. Previous cuttings-transport studies with foam were limited to low-pressure and ambient-temperature (LPAT) conditions. An experimental study of cuttings transport with foam in a horizontal annulus was performed under simulated downhole conditions.

Introduction

Foam drilling fluid can provide low density as well as flexibility in equivalent-circulating-density (ECD) control. However, the complexity of foam flows makes it difficult to obtain reliable predictions of ECD for foam drilling. When drill cuttings are in the wellbore, the foam/cuttings mixture affects bottomhole pressure, making the complicated compressible foam flow even more complex. Therefore, cuttings transport with foam should be well understood for accurate bottomhole pressure and ECD estimation.

Studies on cuttings transport by foam fluids are limited. Although cuttings in foam affect hydraulics calculations and ECD predictions, it is generally accepted that foam cuttings transport in vertical wells is very efficient. Foam-flow velocity of 120 ft/min is sufficient for most vertical-well foam drilling; in some cases, flow velocity as low as 70 ft/min has been successful. For foam drilling in horizontal wells, the particle-settling velocity is perpendicular to foam-flow direction and drill cuttings tend to settle to the low side of the wellbore. The density of drill cuttings is much higher than the density of foam. Therefore, the mechanisms that govern cuttings transport are different for horizontal wells. Empirical correlations and models developed for vertical wells may not be valid for horizontal and inclined wellbores. This research project studied cuttings transport with foam in simulated downhole conditions for more-reliable bottomhole pressure and ECD predictions.

Experimental Study

Experiments of cuttings transport in foam were conducted at the Advanced Cuttings Transport Facility at the U. of Tulsa. The facility is designed to investigate cuttings transport and hydraulics of both compressible and incompressible drilling fluids under elevated-temperature and -pressure conditions. The facility can simulate both pipe and annular flow at pressures up to 1,500 psig and temperatures up to 200°F for incompressible Newtonian and non-Newtonian fluids. It also accommodates compressible fluids such as aerated fluid and foams.
Overview: Drilling and Completion Fluids (November 2006)
Authors: Scott Paul D.
Published: February 2015

In reviewing the fluids-related papers to be featured in this issue, I was struck by the wide range of choices that exists for drilling and completion fluids today. We are no longer constrained to the use of a handful of basic water- or oil-based fluids, clear brines, or simple pneumatic fluids to do our job.

Likewise, we are no longer limited by a few surface measurements and basic concepts to describe and understand the physical behavior of the fluids that are used. Clearly, this increased selection and our ability to test, predict, monitor, and understand the behavior of all wellbore fluids have contributed greatly to the success of our industry in drilling increasingly complex and challenging wells.

Professionals who make decisions about fluids have more challenges than ever before. These challenges include overcoming marketing glitz and information overload to understand when and where true benefits can be derived from use of nonstandard fluids and more-complex-fluid analysis.

Normally, I get on my "plastic-viscosity/yield-point" soapbox here, but what comes to mind is that we are challenged to remember and use the basic engineering science behind what we are doing, most of which was described by the previous generation of SPE professionals in the classic papers with paper numbers below 10000.

I encourage you to read the summaries and review the list of "additional reading" papers that follow. Then I challenge you to take the next step and read the entire paper for the topic that is of greatest interest to you. And once you have done that, review the references and consider the classic SPE papers that laid the foundation for the work being presented—if you have never read them, do yourself a favor and take the time to do so.

Regardless of whether you are evaluating the most-challenging high-cost well to be drilled this year helping to access the next deepwater giant field or a series of assembly-line low-cost wells that help the industry access unconventional resources, knowing your fluids choices and understanding when and where to use them can make the difference between success and failure.

Drilling and Completion Fluids additional reading available at the SPE eLibrary: www.spe.org

SPE 99080 "How To Unify Low-Shear-Rate Rheology and Gel Properties of Drilling Muds: A Transient Rheological and Structural Model for Complex-Well Applications" by B. Herzhaft, Inst. Français du Pétrole, et al.

SPE 96342 "Selection and Evaluation Criteria for High-Performance Drilling Fluids" by K. Morton, Chevron Energy Technology Co., et al.

SPE 97018 "Evaluation of Equivalent Circulating Density of Drilling Fluids Under High-Pressure/High-Temperature Conditions" by O.O. Harris, SPE, U. of Oklahoma, et al.
Fate of Nonaqueous-Drilling-Fluid Cuttings Discharged From a Deepwater Well
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98612, "Fate of Nonaqueous-Drilling-Fluid Cuttings Discharged From a Deepwater Exploration Well," by T.J. Nedwed, J.P. Smith, SPE, and H.R. Melton, SPE, ExxonMobil Upstream Research Co., prepared for the 2006 SPE Eighth International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Abu Dhabi, UAE, 2–4 April.

The full-length paper describes results of a study of the fate of cuttings drilled with nonaqueous drilling fluids (NADFs) and discharged into a deepwater environment. The study characterized effects of discharges from a single-well drilling program and tested the accuracy of a discharge model that predicts seabed cuttings accumulations.

Introduction

Drilling programs increasingly use NADFs to drill more-challenging wells, such as those in deep water or those requiring highly deviated wellbores. Recent field studies have addressed the environmental effects of the discharge of cuttings drilled with NADF. Similar physical, chemical, and biological phenomena control the fate and effects of drilling discharges in all water depths. However, greater water depth could influence discharge fate and effects by providing increased opportunities for dispersion or other changes in cuttings properties during settling to the seafloor. The full-length paper details a study that used novel deepwater sediment traps to sample drill cuttings as they arrived at the seabed.

Method

Drilling Program. An exploration well was drilled to a total depth of 2430 m below the seabed in 950 m of water in the south Atlantic. Over a 9-day period, NADF was used to drill the bottom 1790-m section of the hole with a 12 1/4-in. drill bit. To separate cuttings from drilling fluid, drilling-fluid returns were processed with a conventional solids-control system comprising two shale shakers operated in series. The cuttings removed from these shakers were discharged 13 m below the sea surface.

Discharge Monitoring. The volume of NADF cuttings discharged was estimated by use of the wellbore volume of the NADF-drilled length plus a 7.5% washout. Drilling records of the length of hole drilled each day were used to correlate discharge volumes and times with ocean-current measurements.

Discharged Material. Drill-cuttings samples were collected at five depth ranges during drilling to determine base-fluid content and particle fall velocity. Base-fluid content was determined by dichloromethane extraction followed by total-petroleum-hydrocarbon (TPH) concentration measurement by a gas-chromatography/flame-ionization detection (GC/FID) method. GC/FID results indicated that the detected hydrocarbons in cuttings were identical to those in the NADFs. As a result, TPH concentration can be considered equivalent to base-fluid concentrations for cuttings samples. Measured cuttings-settling times in a laboratory settling column filled with seawater provided data on cuttings-particle fall-velocity distributions for use in modeling.
Techbits: ATW Leads to Formation of Group To Promote In-well and Subsea-Based Fiber-Optic Monitoring Systems
Authors: JPT staff _
Published: February 2015

After the first in-well optical-sensing-system installation in 1993, the oil and gas industry has been pursuing optical sensing as a means of improving reliability and developing new capabilities for in-well reservoir-monitoring applications. Since that first installation, the industry has built a track record with more than 100 installations of permanent pressure and temperature gauges, optical flowmeters, and seismic arrays and hundreds of distributed-temperature-sensing (DTS) installations. But virtually all of these installations have been in dry-tree and land wells.

In 2005, discussions began on soliciting SPE's help in organizing an Applied Technology Workshop (ATW) that would increase awareness in the upstream industry of the potential for widened application of in-well optical-sensing systems in subsea applications and help identify the challenges and barriers facing widespread market acceptance—and then possibly lead to a plan that addresses these obstacles.

After a full year of preparation, an SPE ATW titled "In-Well Optical Sensing—Subsea Well Applications: Are We Ready?" was held in February 2006 in Galveston, Texas. Cochairing the event were Brian Drakeley (Weatherford International) and Brock Williams (BP), and they were joined on the Technical Program Committee by Lars Vinje (Statoil), Herbert Lescanne (Total), Brian Llewellyn (Chevron), Rod Fors (Shell), Garth Naldrett (now of FloDynamic), Ted Drell (FMC Technologies), and Matthew Smith (Deutsch), representing a cross section of companies involved with this emerging technology. The workshop was attended by approximately 130 people from Brazil, Canada, France, Germany, Indonesia, Japan, Norway, the United Kingdom, and the US.

Informative educational sessions were held, starting with presentations covering the types of in-well optical-sensing systems currently available and those under development. These includedPressure and temperature sensorsFlow and fraction metersOptical accelerometers for seismic sensingDistributed temperature sensingDistributed pressure sensing

A number of case histories for these systems were also presented, which varied from the good to the bad to the downright ugly! The openness and honesty of a number of the presentations and the ensuing discussions were very much appreciated by those present and set the ATW off to an excellent start.
Management: The Challenge of Lessons Learned: Overcoming Barriers to Successful Application
Authors: Dressler Don , Palen Walt
Published: February 2015

We have all seen this before: A project team realizes too late that the approach taken or the operational equipment deployed has failed—and it is not the first team to come to that conclusion. If only the lessons learned by others had been sought and applied early in the project.

Look at another scenario: A team learns a valuable lesson during the project but manages to repeat the same mistake again. Perhaps the blame lies in a personnel change or the lack of a systematic way of incorporating the lessons learned earlier. The bottom line is that the team pays the price twice for not learning from experience.

The above examples illustrate the challenge of effectively applying lessons to improve individual, team, and company-wide performance. Industry surveys confirm the spotty track record of effectively benefiting from lessons learned. A 2007 Ernst & Young survey found that 91% of respondents believe that lessons-learned reviews yield valuable results, yet only 13% perform reviews on all programs. The findings from a LogicaCMG survey in 2006 concur, with 51% of the respondents believing that knowledge is poorly managed.

The Nature of Lessons Learned

So what do we mean by a "lesson learned"? It is important to establish an operational definition because the term can mean many things to many people. A lesson learned describes the knowledge gained when results of a project or activity differ from expectations. The difference can be quite dramatic—such as understanding what led to a spectacular success vs. an abysmal failure. The bigger the gap, the greater the potential there is for learning. A smaller gap also has value in highlighting opportunities for continuous improvement.

A lesson can be very simple and explicit, or it can be complex, and the capture or recording of each differs. An example of a simple, explicit lesson involves the proper use of a piece of equipment. These often can be captured straightforwardly and accurately. Complex lessons, on the other hand, often involve much more subtle concepts; the proper interpretation and application of such lessons hinge upon understanding the context or situation. Capturing complex lessons also requires careful judgment and experience because improper application can be disastrous. Application of complex lessons requires "tacit" knowledge that is difficult to write down and often is best shared through a face-to-face dialogue with those who have the experience and knowledge.
Overview: Drilling and Completion Fluids (November 2007)
Authors: Scott Paul D.
Published: February 2015

Drilling and completion fluids are the lifeblood of each well drilled. The effective use of fluids technology and an under-standing of fluid behavior can mean the difference between success and failure. Fluids have a significant influence on rate of penetration; amount of trouble time; cementing success; health, safety, and environment issues; time to drill and complete; and the ultimate reservoir performance for many wells.

There you have it—know what you are doing with regard to drilling and completion fluids, and you will easily outperform your peers. For those of you who do not take the time to sort fact from fiction and insist on rigorous engineering evaluation of the fluids you use, good luck. Take a look at the industry statistics, and crunch the numbers. The value lost to fluids-related problems is an enormous economic drain on the industry and a huge opportunity lost.

Last year, I wrote about today's increased understanding in fluid behavior and the increased number of fluid options we have today; that trend continues—but pick your tools carefully. If you could have read between the lines last year, you would have noticed that I indicate that there are fewer classic papers these days, too little rigorous science applied to drilling and completions fluids, and too much commercial publishing. Those trends also continue.

The Editorial Committee members who write these overviews also pick the technical papers summarized and highlighted in each issue. To those whose papers were selected, congratulations. To those who did not make the short list, thank you for the contribution. For those of you who are business associates and friends, please understand that I raise the bar for those closest to me.

Take time to read the summaries, and note the suggested additional reading; all seven papers are keepers.

Drilling and Completion Fluids additional reading available at the SPE eLibrary: www.spe.org

SPE 103336 "Drilling Fluids in an HP/HT Reservoir: Experiences With Three Different Systems on the Kristin Field Development" by S.A. Hansen, SPE, Statoil, et al.

SPE 103934 "Successful Drilling of Oil and Gas Wells by Optimal Drilling-Fluid Solids Control—A Practical and Theoretical Evaluation" by B. Dahl, Statoil, et al.

SPE 103731 "HP/HT Drilling-Fluids Challenges" by Ron Bland, SPE, Baker Hughes Drilling Fluids, et al.

SPE 103088 "Apparatus for Measuring the Dynamic Solids-Settling Rates in Drilling Fluids" by R. Murphy, SPE, Halliburton, et al.
Mud Design To Prevent Circulation Losses
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105449, "Design of Well Barriers To Combat Circulation Losses," by Bernt S. Aadnoy, SPE, Mesfin Belayneh, SPE, and Miguel Arriado, U. of Stavanger, and Roar Flateboe, BP plc, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February.

The full-length paper summarizes a 10-year research program in borehole fracturing and mud design. Numerous experiments were conducted with oil- and water-based drilling fluids to understand better the mechanisms that lead to circulation losses. A new mechanistic model for fracturing is presented that is different from other recent models, and the model was verified with laboratory experiments. The model defines optimal barrier filtrate loss to place particles in the loss zone. Selected laboratory experiments are presented that demonstrate that borehole fracturing resistance can be improved significantly by changing mud composition.

Introduction

Recognizing that borehole-stability mechanisms are not understood fully, research carried out during the past 10 years has focused on the fundamental physics and chemistry. Fig. 1 shows a fracturing cell where specially prepared hollow concrete cores are fractured. The setup also allows for mud circulation to ensure that mud particles are well distributed inside the hole. The cell is rated to 69 MPa, and the axial load, confining pressure, and borehole pressure can be varied independently. Many oil- and water-based drilling fluids were tested as well as novel ideas such as changing rock wettability or creating other chemical barriers. Cores with circular, oval, and triangular holes were tested to study effects of hole geometry.

Fig. 2 shows typical results from the fracturing experiments. The commonly used Kirsch equation defines the theoretical fracture pressure in a nonpenetrating situation such as when using drilling muds. Only one of the three measured fracture pressures agrees with the theoretical model, and the other two are much larger. Several conclusions came out of this research.The theoretical Kirsch model underestimates the fracture pressure in general.There is significant variation in fracture pressure, depending on mud quality.

This shows that the fracture pressure can be increased by designing a better mud.

Several devices were constructed to study the mud and its filter cake. Fig. 3 shows a mud cell with six outlets to simulate fractures of various dimensions. The mud is circulated with a low-pressure pump to develop a filter cake across the slots. Then, a high-pressure pump increases the pressure until the mudcake breaks down. In this way, the stability and strength of the mudcake can be studied. Common muds and additives were used, and the observation was made that reducing the number of additives often results in a better mud. Nonpetroleum products also were studied to look for improvements.
Overview: Tight Reservoirs (November 2007)
Authors: Mayerhofer Mike
Published: February 2015

Nothing has changed over the last year; high oil and gas prices are still providing a major boost to tight-reservoir development. However, costs have been rising because demand for services is high. North America has seen a "boom" of startup service companies that specialize in pumping hydraulic-fracture treatments. A surge of horizontal-well development in shale reservoirs is one of the reasons for the significantly increased demand for hydraulic-fracturing services. Instead of one fracture treatment per vertical well, horizontal wells are treated with up to a dozen individual fracture treatments in a short period of time requiring enormous amounts of water and fracturing materials on location. Moreover, in some cases, two to three offsetting horizontal wells are fracture treated simultaneously to achieve the best possible stimulation and drainage efficiency.

In addition to "supertight" shale reservoirs, horizontal-well development also has moved back into the more traditional domain of tight-sandstone reservoirs, such as the Cotton Valley in east Texas and others. Significant advances in drilling efficiency and technology have been made as a result of this high activity, enabling high flexibility for well trajectories while providing a wellbore that meets the needs for the specific completion strategy. Horizontal-well completion strategies include mainly cased-and-cemented wells, but recently, uncemented laterals with openhole packers for stage isolation have become more popular because an entire wellbore can be fracture stimulated with back-to-back treatments in a single day. Diagnostic technologies, such as microseismic and tiltmeter fracture mapping and radioactive and chemical tracer logs, complement innovative drilling and completion technologies by providing a picture of what is happening during fracture treatments and showing how efficient the different completion technologies are in stimulating the entire horizontal wellbore.

In conclusion, times are still exciting for tight reservoirs and likely will continue to be that way for many years to come.

Tight Reservoirs additional reading available at the SPE eLibrary: www.spe.org

SPE 102745 "4D Pressure Pilot To Steer Well Spacing in Tight Gas" by E. Quint, Shell E&P Americas, et al. [See JPT (February 2007) 86]

SPE 108110 "Productivity and Drainage Area of Fractured Horizontal Wells in Tight Gas Reservoirs" by F. Medeiros, SPE, Petrobras, et al.

SPE 102801 "Imaging Seismic Deformation Induced by Hydraulic-Fracture Complexity" by S.C. Maxwell, Pinnacle Technologies, et al. [See JPT (March 2007) 54]
Your SPE: Enhancing the SPE Value Proposition in China
Authors: Roodhart Leo
Published: February 2015

President's column

One of my last trips as President-Elect was to China. My visit was marked by two key events: the recent tragic earthquake in Sichuan and the excitement leading up to the Olympics. These topics were on every agenda, together with SPE and the oil industry, of course.

I went to China to talk to company leaders and representatives of four of the five active sections about how the industry might develop over the next 20 years and how SPE can help it to respond to a rapidly changing world. There must be millions of engineers in this country with a population of over 1.3 billion people. But total SPE membership is just 1,740, with most members belonging to the Beijing, Daqing, Northern China International, and Southern China sections. My challenge in China was to communicate SPE's value proposition: SPE is not just about conferences and workshops but has a role as a relationship broker between engineers and the providers of knowledge. It provides a vehicle for individuals and companies to maximize business and networking opportunities through events, publications, and electronic media—a concept that the senior management of the Chinese NOCs finds difficult to understand. They view SPE membership as valuable at a corporate level, offering "a window on the external world." The senior company executives have calculated exactly how many members they need to ensure an effective distribution across their organizations of JPT magazines, access to the eLibrary, and notice of upcoming workshops and conferences. They are very supportive of SPE's sister organization in China, the Chinese Petroleum Society, which publishes many Chinese technical papers and hosts events around the country.

Dues of members in the Beijng, Daqing and Southern China sections are paid by their companies. Membership numbers will increase only as a result of further added value rather than from lower dues. So, how do we boost membership in China?

Discussions during my meetings offered a few solutions. All sections requested that we set up a program of regional (meaning Chinese) Distinguished Lecturers and a Chinese-language professional network targeting those nationals who work outside China. However, Chinese translations of SPE papers was not seen as adding value, particularly in the China National Offshore Oil Corporation, where the objective is to encourage engineers to learn English.

I am one of SPE's main advocates of further globalization of the Society, so how do I match that objective with listening to local needs that call for a more insular approach, which is totally in keeping with the Chinese culture and which we must respect?
Acid-Tunneling Technique Shows Success in Carbonates
Authors: JPT staff _
Published: February 2015

Technology Update

Rising oil prices and increased efforts to maximize oil production have created global interest in technologies that economically can extend well lifetime. As fields mature, stimulation technology costs become marginally economic as production improvements decline.

For wells completed openhole in carbonate reservoirs around the world, an acid-tunneling technology developed by BJ Services has been shown to provide an economic and efficient stimulation alternative.

The patented process, called StimTunnel, uses coiled tubing (CT) to convey a jointed nozzle that jets acid at the formation rock, dissolving it to create numerous mechanically stable, stimulated tunnels into the formation (Fig. 1). These tunnels, and the multitude of wormholes and expanded pores, increase reservoir contact and improve productivity by distributing inflow across more surface area (Rae and di Lullo, 2001).

Applicable in openhole completions in limestone or dolomite formations, the technology does not require a drilling rig and has no fluid returns, resulting in very low environmental impact.

Economically, the acid-tunneling compares favorably with alternative stimulation options in both cost and time savings. This is especially true when considering resulting production improvements.

The use of these treatments began in Venezuela, Spain, and Indonesia, and recently has spread to Kuwait, Romania, the US, and Libya.

Early Results

The initial field trials of the technology were in the massive Mara carbonate field near Lake Maracaibo, Venezuela, during 2005, where typical permeability is in the range of 1 to 5 millidarcies (md).

In operation, the jointed tool is run on CT to the desired tunneling kickoff depth. Acid is pumped, and the internal CT pressure activates the kickoff tool to make contact with the formation face. Acid is jetted from the nozzle, dissolving the formation face and forming a tunnel entry area in the rock matrix. After tunnel initiation, the CT run into the well will push the tool into the reservoir so that the acid can dissolve more of the formation ahead. When the desired tunnel length is attained, pumping ceases and the CT is pulled out of the tunnel. This process is repeated higher uphole as many times as required, at different elevations.

Typical tunnel lengths vary from 3 to 60 ft, although tunnels longer than 100 ft have been created. Because it is intended for relatively short tunnels, the bottomhole assembly (BHA) does not incorporate a steering tool or telemetry systems to relay inclination or azimuth information back to surface.
Progress and Challenges for Health, Environment, and Safety in Exploration and Production
Authors: Arscott Lyn
Published: February 2015

Management

A computer-based survey was taken of the program committee members of five SPE International Health, Safety, and Environment (HSE) Conferences over the past 5 years. The committee members are experts in their fields and they were asked to express their opinions on the progress of the industry in HSE over the past 5 years and the effort that the industry should make over the next 5 years.

The committee members were asked to complete a web-based questionnaire with the following questions:How would you rate the progress made by the industry in the following subjects over the past 5 years? (excellent, good, moderate, poor, very poor)How would you rate the effort that the industry should make in the next 5 years? (much more effort, more effort, same effort, less effort, much less effort)How would you rate the effort the regulators should make in the next 5 years? (much more effort, more effort, same effort, less effort, much less effort)How would you rate the effort that the nongovernmental organizations (NGOs) should make in the next 5 years? (much more effort, more effort, same effort, less effort, much less effort)

The method of scoring and ranking is summarized in the appendix. A summary of the status of the industry programs is shown in Table 1 with the full results in Tables 2–4. Of the list of 20 questions, 16 were asked at all five conferences but 4 new questions were asked at the 2008 conference in Nice, France.

The chart in Fig. 1 shows the scores for progress from the Nice (2008) conference. The seven issues in the first column of Table 1 are the highest-ranked items in the Progress list based on the results from Nice as shown in Table 2 and have been categorized as "good progress," while the six issues in the third column of Table 1 are the lowest-ranked issues from the Progress list and have been categorized as "needs more effort." The issues in the second column are those issues in between the other two categories and have been categorized as "maturing." The issues in the table are, therefore, in seriatim order for the progress scores and the numbers in the parentheses are the rank for the future effort score.
Minimizing Risk of Gas Escape in Gas Storage
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113509, "Minimizing Risk of Gas Escape in Gas Storage by In-Situ Measurement of Gas Threshold Pressure and Optimized- Completion Solutions," by L. Ostrowski, SPE, Baker Hughes, and B. Ulker, RWE Dea A.G., originally prepared for the 2008 SPE Europec/EAGE Conference and Exhibition, Rome, 9-12 June. The paper has not been peer reviewed.

Underground gas-storage operations and carbon dioxide (CO2) sequestration in aquifers rely on proper wellbore construction and on the sealing function of the caprock. Potential leakage paths are by migration along the wellbore as a result of poor cementation and flow through the caprock. Capillary pressure data, which are critical for prediction of gas leakage through the caprock, are seldom available and yet are necessary. An in-situ method of determining gas-entry pressure was developed to help reduce uncertainties in gas-leakage predictions. Simulations were performed using this gas threshold entry pressure to investigate the gas leak-age amount through the caprock and along the wellbore for both natural-gas- and CO2-storage models.

Introduction

Capture and geologic storage of CO2 are being considered to reduce CO2 emissions. Managing geological storage requires an understanding of the processes and risks, including the likely time scales and flux rates involved. Key processes are the migration of CO2 after injection into deep geologic formations, stratigraphic trapping, dissolution, residual-gas trapping, mineralization, and potential leakage. The storage capacity of an underground CO2-storage project must be related not only to the amount of CO2 that can be stored but also to long-term storage effectiveness. Experience with underground natural-gas storage provides useful insight into the geologic storage of CO2. Both methane (CH4) and CO2 are less dense than the usual formation water and thus exhibit a tendency to migrate to the top of the storage formation. Potential leakage of CO2 and CH4 from the storage formation can occur through the caprock, along the wells, and through faults and fractures. In many instances, underground natural-gas- storage projects are operated at pressures exceeding the initial reservoir pressure. Overpressurization usually occurs at the early stages of storage and is essential for increasing storage capacity and gas deliverability. This overpressure can result in pushing water out of the caprock and causing gas to leak from the storage formation. In CO2-storage projects, less is known about the risks of leakage through the caprock because of lack of experience. It is essential to determine the gas-entry pressure into the caprock before proceeding with any gas-storage project.
Comments: Weathering the Recession
Authors: Donnelly John
Published: February 2015

Editor's column

A new report sheds light on how oil and gas firms have weathered the recession, and whether the firms" management believes that the industry is experiencing permanent structural changes in addition to the significant economic downturn.

Released on the eve of the SPE Offshore Europe conference, the report concludes that companies generally fall into one of two categories and that the determining factor is company leadership and corporate culture. Although the entire industry has been affected by the recession and the cyclical nature of oil prices, the study sought to discover why some firms are more resilient and optimistic when facing economic and other challenges. The "Riding the Rapids" survey was put together by the Aberdeen School of Business and the Production Services Network consulting firm and was based on interviews with senior leadership from oil and gas operators and service companies. The research was then debated and discussed in panel sessions held in Aberdeen, Houston, Calgary, and Abu Dhabi.

Companies were split on how they viewed current economic challenges. More than three-quarters of the companies said they had been affected in some way by the banking meltdown and the oil-price volatility of the past year and a half. But just over half (51%) claimed they were immune or only moderately affected by the current economic downturn and seemed to welcome the challenges the downturn posed. In sharp contrast, 49% of the companies surveyed "felt exposed and less in control of their destiny, stating they had been seriously or very badly affected by the current recession."

The more optimistic firms saw the recession as only one of several contextual factors driving change in the industry. They also saw more signs of economic and industry recovery occurring in the second half of this year, which could lead to an industry rebound in 2010. Management in these companies were focused on restructuring their companies to become "leaner and meaner" in days to come to perform more efficiently. Not surprisingly, these firms often had a product line that was more economically inelastic, diversified offerings, and sound management practices and sturdy financials that were already in place. Some saw a practical opportunity to the boom and bust economic and price cycles the industry weathers—it allows the industry to periodically realign itself to current economic realities, streamline costs, and emerge as a more efficient sector.

The more vulnerable cited the banking crisis in particular as a factor, as the lack of access to capital and funding harmed the ability to secure finance for projects and new developments and affected cash flow throughout the supply chain. They also cited a lack of skilled workers. The industry faced that problem before the recession and economic difficulties only made matters worse for some firms, which laid off workers even in light of the technical-talent shortage. Other firms in this category also complained about the lack of help and incentives from government, even as it bailed out other industries.
Bringing the Digital Oil Field to Production Operations
Authors: Mahdavi Mehrzad , Darukhanavala P.P. (Duru) , Paul Donald
Published: February 2015

Guest editorial

Things move fast in the world of digital technology. And the oil industry has often been in the advance guard.

Progress in the seismic area, accelerated by high-performance computing, has been nothing short of amazing, and the industry has truly pushed the envelope in deepwater exploration thanks to adoption of vanguard technologies. In addition, the industry has advanced significant initiatives to digitize field operations, from installing field wireless networks and sensors to deploying wellbore fiber optics.

However, upon reflection, most progress has come in exploration or field development. In "operations," the Digital Oil Field of the Future (DOFF) has moved ahead in small, measured steps. Is it possible to accelerate adoption of digital innovation in the traditional, cautious world of production operations?

The external world has experienced an explosion in the development and adoption of new digital technology. In the past decade, the Internet has morphed from minor brochureware to a major business channel and the smartphone has become a game-changing device right out of the gate.

The next generation of computing—cloud computing—is taking shape in a big way, bringing game-changing technologies and business models.

And so—could our progress in the oil field be faster? The complexities and barriers are significant. Four in particular impact the pace of change:Wide Diversity of Industry, Assets, and Participants. Production-operations deals in new fields and brownfields, international oil companies (IOCs), national oil companies, and independents, all have different value propositions. There can be no "one size fits all" DOFF solution. This diversity and a lack of focus in industry efforts supporting DOFF have led to small-scale, independent DOFF efforts across—and even within—companies. The consequent slow progress and disconnected processes have made it difficult to mount efforts that reach economies of scale.Lack of Industry Standards. Suppliers have a vested interest in protecting their proprietary solutions rather than developing industry standards; likewise, IOCs are inclined to see their DOFF initiatives as potentially providing competitive advantage, reducing any willingness to share. However standards and integration of technologies will be essential to reach the economies of scale necessary to drive widespread adoption.
Comparing Friction Reducers' Performance in Produced Water from Tight Gas Shales
Authors: Ferguson Marcelle L. , Johnson Michael A.
Published: February 2015

Technology Update

Natural gas plays a key role in meeting the energy demands of the United States, and the production of natural gas from tight shale formations is expanding rapidly as the demand for clean and efficient energy rises. Slickwater fracturing, a hydraulic fracturing technique whereby a water-based fluid is injected into a well at intense pressures—causing the formation rock to crack, or fracture—is the most commonly used stimulation technique in tight gas reservoirs. Slickwater fracturing treatments involve combining a base fluid with a friction reducer, a polymer that enables faster pumping of the fluid into the formation, and a propping agent, or proppant—a granular substance, such as sand, that is carried into the formation by the fluid and holds the fractures open once the treatment is complete.

Each stage of a slickwater-fracturing treatment requires tens of thousands of barrels of fracturing fluid. Furthermore, each slickwater treatment generates a great deal of wastewater, as most of the fracturing fluid will flow back out of the well, and production brines, or produced water, will flow back over the long term. Programs for managing produced water are on the rise, as technology for convenient and economical treatment of wastewater improves. However, often the most cost-effective and convenient use of produced water is to reuse it in subsequent fracturing treatments.

Evaluation of friction-reducer performance in the reused water is crucial because produced water from most of the US tight shale formations contains elevated levels of dissolved solids, compared with fresh or tap water. Reusing waters with high levels of total dissolved solids (TDS) can lead to adverse interactions between the friction reducer and the base fluid. The adverse interactions result in elevated treating pressures, and this is often overcome by introducing more of the friction reducer into the mixture, which leads to higher chemical costs for the treatment.
Focus on Africa: Betting Big on Africa
Authors: Marks Harvey
Published: February 2015

Chevron has deep roots in Africa. The company began marketing operations on the continent in 1911 and drilled its first well there in 1958. From these relatively modest beginnings, Chevron's commitment to Africa—as well as that of other major operators—has grown as the continent's stature as a major petroleum province has risen. In the last five years, Chevron has invested more than USD 13 billion in Africa, including deepwater projects in the Congo, Nigeria, and Angola, as well as operations in Chad and Libya.

In 2008, those countries represented 15% of companywide production, including oil sands, and that figure is certain to increase as new African projects ramp up production.

By 2011, new projects in Africa are expected to add another 620,000 BOPD to the company's output. On top of that, there are ongoing discoveries. These include the Moho Nord Marine-4 well in the Republic of the Congo, which was confirmed in May. It is located in the Moho-Bilondo license approximately 46 miles offshore in 3,537 ft of water. Drilling was to a total depth of 13,907 ft and proved a 535-ft column of high-quality oil flowing at 8,100 B/D. Partners in the Moho-Bilondo field include Total E&P Congo, the field's operator, and Société Nationale des Pétroles du Congo.

"This exciting discovery emphasizes the future potential of this region in which Chevron and its partners have already made significant energy investments," said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production. He added that maximum total daily production of 90,000 bbl of oil from Moho Nord Marine-4 is expected in 2010.

This discovery follows two previous successful exploration wells, Moho Nord Marine-1 and -2, drilled in the permit area in 2007, and the positive appraisal well Moho Nord Marine-3 in 2008. The Moho-Bilondo field, which consists of subsea well clusters that flow into a floating processing unit, was discovered in 1995 and began production in April 2008.
New Training Alliance Focuses on Industry's Skills Shortage
Authors: Edmundson Henry
Published: February 2015

Talent & Technology

In recent times, it has become commonplace to read of the oil and gas industry's skills shortage. E&P projects large and small have been severely limited by supply-chain shortfalls of all kinds, but most notable has been the lack of availability of petrotechnical expertise. Known so familiarly as the "great crew change," our expertise shortage today is due mainly to the industry's poor or nonexistent recruiting in industry-periodic downturns, particularly during the late 1980s.

The age demographics of petrotechnical professionals in different operating companies vary enormously, but three factors are usually present. First, the midcareer range tends to be depleted everywhere. Thus, companies are under huge pressure to develop their young people faster than they are accustomed. Second, companies have been very actively recruiting in recent years, at least until the global recession and associated oil and gas price fall, and therefore the number of young recruits requiring professional development is larger than ever before. Third, companies cannot ignore the development of personnel of any age and experience as new technology continually comes into play and must be learned.

So how to get the most bang for our buck when it comes to professional development? Numerous studies have sought to understand the return on investment in training. Time and again, it has been shown that training based on a competency model provides the surest route to spending training money wisely. Competency models provide a firm baseline for assessing skill levels and ensuring training is fit for purpose. It has been shown that training based on a competency model shortens time to professionalism, or time to autonomy as it is also referred to, by at least two years.

Studies also point to the advantage of using a mix of learning methods rather than relying on just one method such as classroom learning. The traditional classroom environment has its place, but so does e-learning, on-the-job learning, case-study learning, and for disciplines such as geosciences, instructional seminars in the field. Finding the right combination at the right time in the development cycle is what counts.

Finally, coaching and mentoring remains an essential requirement in any training program. Training must develop both discipline knowledge and the experience to apply that knowledge. Gaining experience takes time, but it can be dramatically accelerated if a coach is present to provide guidance and a helping hand. Good technical coaching and mentoring is a recognized attribute of all leading training programs.