bluuebunny/crossref_metadata_2025 huggingface dataset:
Shared Vision (June 2005)
Authors: Paccaloni Giovanni
Published: February 2015

Sharing our time and our talents is essential to the long-term success of SPE. Volunteerism is one of SPE’s core values. As a volunteer-driven organization, we enlist the talents of our members to address both local needs and the broader interests of our global membership. Members work together to direct SPE activities, from planning the details of section meetings to developing a long-term plan that defines the future for the Society. Your participation ensures that SPE remains vibrant and relevant.

Volunteering also pays personal dividends for the time you invest. You can gain leader-ship experience or learn interpersonal skills that you may not be able to get in your job. You can meet and network with people who can help you solve problems and move ahead in your career. You can write technical papers and receive recognition for it. Many are motivated simply to be of service: to help others, to “give back” to the profession, and to make a difference in the world. Winston Churchill explained the value of volunteering this way: “You make a living by what you get, but you make a life by what you give.”

Despite the many rewards of volunteering, the demands of modern life make it more and more challenging for members to give their time. Some smaller sections have a tough time filling leadership positions—the same people continue to serve year after year. All too often, members say they are too busy to attend monthly meetings, much less take on a greater role as a volunteer. In fact, members everywhere cite similar reasons why they do not volunteer.

“I’m too busy.” People are busy—with the consolidation that has occurred in this industry over the last two decades, fewer people are handling more projects, and the pace of change is incredible. Our members are juggling the demands of family life as well. We must respond to the time constraints of our members by offering opportunities to serve in smaller bites of time. By doing a better job of planning section and committee tasks, we may be able to break a big job into smaller parts that several people share. Participating in online communities is another option, allowing you to sign on at a convenient time. We have begun conducting a considerable amount of SPE business through email, online communities and teleconferences to reduce the number of meetings for Board and committee members.

“I don’t have the support of my boss.” This is really a variation of the first reason—your manager believes you are too busy to take part in SPE activities. Part of my role is to make sure that industry executives are aware of the tremendous resources and value that SPE offers to professionals at all career levels. The key to getting management’s support is to demonstrate that your participation in SPE pro-vides an exceptional return on the investment of your time. The company benefits when you gain access to the latest technical knowledge and develop skills that will enhance your performance.
Overview: Coiled-Tubing Applications (June 2005)
Authors: Blount Curtis G.
Published: February 2015

Having been involved in coiled-tubing (CT) technology for many more years than I care to admit, it is interesting to see how much has changed during the last quarter century. Improvements in CT manufacturing, materials, equipment design, and computerized monitoring, as well as a better understanding of CT mechanics, set the stage for rapid growth and acceptance of CT as a viable and versatile oilfield tool. I firmly believe that, following this initial technology surge, the advent of various knowledge-/experience-sharing conferences and joint-industry projects, focused solely on CT technology and needs, have accelerated this CT “revolution.”

The first technology-transfer gatherings I recall attending were the HydraRig-sponsored forums beginning in 1989 through the World Oil CT conferences beginning in 1993. There also were several other public and intercompany events offering forums for CT pundits during the 1990s. In 1996, recognizing the need to share ideas on a larger scale, the Intl. Coiled Tubing Assn. (ICoTA) introduced its roundtable conferences. ICoTA soon teamed with SPE to bring us what is now considered the premier CT technology-transfer forum. This year, estimated attendance at the 2005 SPE/ICoTA Coiled Tubing Conference and Exhibition was 880—up 100 from last year—not including an additional 57 Texas A&M U. students we “graying” technologists were happy to welcome.

As I was reviewing papers from recent SPE and SPE/ICoTA conferences for this month’s feature on CT technology, it became apparent to me just how much the focus of the CT conference papers has changed. It seems to me that most early-conference papers centered around CT mechanics—on why CT behaves the way it does and predicting when it will break—and around successful CT jobs for any number of applications.

Recent offerings focus more on mainstream issues and what I call CT exploitation.

- Reducing the cost and extending the market for CT drilling services.

- Improving operational and safety efficiency.

- Discussing successful CT programs.

- Delivering solutions to complex problems in areas lacking economically viable alternatives.

And, of course, there still are the ubiquitous novel and unique thought-provoking sub-jects the innovative CT community is known for.

Additional Coiled-Tubing Applications Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 92513 Underbalanced Coiled-Tubing Drilling: Update on a Successful Campaign

SPE 94058 Some New Developments Applicable to Coiled Tubulars

SPE 94159 World’s First Utilization of Coiled Tubing to Dissolve Hydrate(s) in an FPSO Riser: Case History

SPE 94102 An Effective Sweep-Cleaning of Large Deviated Wellbores Using Small Coiled-Tubing Systems

SPE 90558 Effect of Coiled-Tubing Curvature on Friction-Pressure Loss of Newtonian and Non-Newtonian Fluids—Experimental and Simulation Study
Technology Update: New Options, Improved Economics from Aerogel Insulation
Authors: JPT staff _
Published: February 2015

The challenges facing oil and gas operators seeking to develop new fields in hostile environments such as deep and ultradeep water are well documented and continue to increase. One important requirement for operators developing subsea fields is the ability to transport unprocessed hydrocarbons, which are frequently at high pressure and high temperature, over longer distances along the ocean floor. Without sufficient insulation, the hydrocarbons will cool and create hydrates/wax buildup that can eventually clog flowlines at significant cost to operators. Cabot Corp. has developed Nanogel aerogel, a nanoporous insulation product, to address associated economic and efficiency issues.

Sometimes called "frozen smoke," aerogels are light insulating solids. Nanogel is a hydrophobic aerogel produced as particles, each of which consists largely of air (≈95%) trapped in nanosized pores that severely inhibit heat transfer through the material.

A proprietary manufacturing method imparts mechanical benefits (NanoSprings) to the aerogel particles in addition to characteristics that make them useful for thermal insulation. The aerogel performs across a range of temperatures (from –200 to +250°C) making it applicable in systems ranging from liquefied natural gas (LNG) to high-pressure/high-temperature settings.

Four products have been developed for the oil and gas market—the Expansion Pack, Compression Pack, Particle Pack, and Thermal Wrap systems. The first two are pipe-in-pipe products and use half-shells made with Nanogel aerogel particles compressed and packed under vacuum. In field application, a series of half-shells is positioned in a pipe-in-pipe or other assembly and activated (vacuum is breached), resulting in form fitting of compressed particles into a desired shape, either filling the entire annular space (Expansion Pack) or, under higher compression, filling a predetermined portion of the annular space (Compression Pack).

Operating Economics

There are two ways in which improved economic impact is created during development of subsea fields—by allowing the use of smaller jacket pipes and by enabling the construction of longer tieback lines.

In the case of smaller jacket pipes, substituting Nanogel for other insulation forms (such as polyurethane [PU] foam/rock wool) allows operators to reduce the size of outer pipes without compromising system performance (U-value), resulting in:Material savings on pipe steel.The ability to fit more pipe sections on a barge or reel, thereby reducing the number of barge trips.The ability to use smaller lay barges that have lower day rates. For example, to achieve a target U-value of 0.7 W/m2·K with an 8-in. flowline, an outer pipe of approximately 14 in. would be required if the insulation were PU foam. With the Expansion Pack system, the size of the outer pipe could be reduced to approximately 11 in. (Table 1).
Flow-Assurance Lessons: The Mica Tieback
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18384, "Flow-Assurance Lessons: The Mica Tieback," by A.L. Ballard, SPE, BP America Inc., prepared for the 2006 Offshore Technology Conference, Houston, 1-4 May.

Flow assurance plays a significant role in asset development. In the case of ultradeep water, the role is major. The Mica field uses the longest tieback in the Gulf of Mexico and has been in operation for more than 4 years. The Mica wells are tied back through two 29-mile flowlines (one for gas and one for oil) to a major facility (Pompano). A review of Mica, comparing original flow-assurance-design strategies with current operational strategies, revealed several learnings, particularly involving paraffin, corrosion, erosion, hydrates, and slugging.

Introduction

The Mica field is in 4,350 ft of water. First production was in 2001. It was decided early on that the Mica wells would be tied back to an existing platform. Three zones in the reservoir were deemed producible. The shallowest zone is a saturated-gas and -oil zone with a gas/oil ratio (GOR) of 1,330 scf/STB, oil gravity of 32°API, and a wax cloud point of 93 to 100°F. The middle zone is a near-critical fluid with a GOR greater than 3,000 scf/STB, oil gravity of 37°API, and a wax cloud point of 90 to 94°F. The deepest zone is a dry gas with a condensate yield of 5 STB/MMscf and condensate gravity of 44°API. Peak capacity from the reservoirs was expected to be 150 MMscf/D of gas and 15,000 STB/D of oil.

Pompano Tie-In. Pompano is a steel-jacket structure in 1,290 ft of water. Weight on the platform was not a major issue, so it was decided to construct a new process system for the Mica wells. Because a relatively small amount of oil was expected compared to gas, a separate gas-export pipeline was built for the gas while the oil was tied into the Pompano crude treater. New equipment built for the Mica wells includes a high-pressure (HP) separator, intermediate-pressure (IP) separator, low-pressure (LP) separator, turbine-driven centrifugal compressor, glycol-dehydration system, and turbine-driven generator. Fig. 1 shows the process system. The compressor suction is drawn from the IP separator at 450 psig and discharged to the gas-export line at 1,300 psig. The LP separator feeds into the Pompano compressors at 150 psig.

Design Challenges

Paraffin. With the cloud-point temperatures of the oil, paraffin issues were expected in the wells and in the insulated oil flowline. For a tieback of this length, it was not feasible to keep the fluids in the flow-line above the wax-appearance temperature during production. Pipe-in-pipe (PIP) insulation was designed for the oil flowline to spread out the deposited paraffin in the flowline as the oil cooled.
Deepwater, Subsalt Drilling From Nova Scotia, Canada - Case Study
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98279, "Pore Pressure Prediction and Drilling Challenges: A Case Study of Deepwater, Subsalt Drilling From Nova Scotia, Canada," by C. Marland, SPE, and S. Nicholas, SPE, Halliburton; W. Cox, EnCana Corp.; C. Flannery, SPE, Murphy Oil Sdn. Bhd.; and B. Thistle, Nexen Inc., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21-23 February.

Offshore eastern Canada is an environment where deep water and the need to penetrate thick salt sheets increase the difficulties faced by drillers. The full-length paper details a deepwater, subsalt-drilling case history and examines the challenges of dealing with high pore pressures and variable fracture gradients. During drilling, conditions were encountered that required use of unconventional borehole sizes and on-the-fly drilling-design modification to deploy unplanned equipment rapidly.

Introduction

The Weymouth A-45 well is approximately 160 miles south by southeast from Halifax, Nova Scotia, Canada, in the deepwater area of the Scotian shelf. Seismic analysis identified the presence of a subsalt anomaly, the 150-m-thick Argo salt sequence. This sequence presented a potential drilling challenge and also a problem for prewell pore-pressure and fracture-gradient planning. Because of the challenges posed by the deepwater environment and the thick salt deposit, the well included a complex well design with concentric hole openers and an unconventional casing design. Despite potential hazards and complex well design, the drilling program allowed flexibility in decision processes and in well design to deal with problems encountered. Flexibility was particularly important when drilling through the salt body with a point-the-bit rotary-steerable system (RSS). Although the RSS was not planned for use below the salt, the success of the system in the shallower parts of the well led to its use below the salt and highlighted the flexibility of rotary-steerable technology.

Planning and Design

In August 2002, three seismic lines and six offset wells were used for initial analysis of the Weymouth Prospect. These data were used to generate overburden, pore-pressure, and fracture-pressure predictions. The six offset wells, including two deepwater wells, showed two different pore-pressure regimes unrelated to water depth.

The first pore-pressure regime was characterized by normal pore-pressure gradients to approximately 2900 m followed by a slow increase in pressure, averaging 22 kg/m3 equivalent circulating density (ECD) per 100 m through to total depth (TD). The second pore-pressure profile had a steeper pressure "ramp" from 3600 m with a rapid pore-pressure increase to 1800 kg/m3 and greater by well TD.
Overview: Reservoir Simulation and Visualization (June 2006)
Authors: Smart Tom
Published: February 2015

In last year's overview of Reservoir Simulation and Visualization, the focus was on technology designed to handle the ever-increasing volumes of data that are readily available for use by reservoir engineers. This trend has continued and has resulted in some extremely innovative adaptations of technology toward reservoir management.

Large volumes of data produce large models, which in turn produce large amounts of simulation results. This large volume of simulation results is difficult to analyze by conventional means. Significant improvements have been made by extending the methods of analysis of reservoir-simulation results to use the senses of hearing and touch, in addition to sight, to better understand the mechanisms at work in large full-field models. Research has been done with methods of artificial intelligence to predict reservoir performance, such as the training of neural networks. It is essential that research continues in these innovative areas as the industry strives to maximize production to meet market demands.

On the traditional front, important research has continued in the area of grid coarsening and scaleup to reduce model sizes to more-manageable levels. Significant contributions have been made by both industry and academia, with improved methods for selecting layers for grouping and with new algorithms for including additional reservoir flow characteristics in the scaleup calculations. As computing power continues to increase, the inclusion of compositional fluids and geomechanical effects in full-field reservoir models is becoming more feasible.

Workflows continue to be invaluable to reservoir management. With the ambitious goal of simulating the geological model, significant work remains to enable seamless transition of geological models through to numerical simulation. As the industry continues to move closer to this goal, we will also move closer to the ultimate goal of managing risk and uncertainty better. Ongoing work to provide the tools to understand both the input and the output of these large models will largely determine the success of this endeavor.

Reservoir Simulation and Visualization additional reading available at the SPE eLibrary: www.spe.org

SPE 96410 "Reservoir Simulation and Reserves Classifications—Guidelines for Reviewing Model History Matches To Help Bridge the Gap Between Evaluators and Simulation Specialists," by D. Rietz, SPE, Ryder Scott Co., et al.

SPE 94319 "Improved Coarse-Grid Generation Using Vorticity," by H. Mahani, SPE, Imperial College London, et al.

SPE 97155 "How To Approximate Effects of Geomechanics in Conventional Reservoir Simulation," by A.T. Settari, SPE, U. of Calgary, et al.

SPE 96416 "Tuning an Equation of State—The Critical Importance of Correctly Grouping Composition Into Pseudocomponents," by A.A. Al-Meshari, SPE, Saudi Aramco, et al.
Optimal Coarsening of 3D Reservoir Models for Flow Simulation
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 95759, "Optimal Coarsening of 3D Reservoir Models for Flow Simulation," by M.J. King, SPE, K.S. Burn, P. Wang, V. Muralidharan, SPE, and F. Alvarado, BP America Inc., and X. Ma, SPE, and A. Datta-Gupta, SPE, Texas A&M U., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.

A new constrained optimization approach to the coarsening of 3D reservoir models for flow simulation has been developed. The optimization preserves a statistical measure of the heterogeneity of a fine-scale model. Constraints arise from the reservoir fluids, well locations, pay/nonpay juxtaposition, and large-scale reservoir structure and stratigraphy. The approach has been validated for several oil and gas projects in that flow simulation through the coarsened model was shown to provide an excellent approximation to high-resolution calculations performed in the original model.

Introduction

The development of coarsened reservoir-simulation models from high-resolution geologic models remains an active field of research. This study had success with the use of coarsening algorithms to determine a reservoir-simulation grid obtained by grouping fine-scale geologic-model cells into effective simulation cells. Results differ from previous studies in that a statistical analysis of the static properties of the model appeared to identify the best grid for dynamic reservoir simulation. Coarsening beyond the degree indicated by the analysis discarded too much of the underlying heterogeneity. It would overly homogenize the properties on the simulation grid. Finer models would retain at least as much reservoir heterogeneity, but they are more costly.

This analysis uses a statistical technique for layer grouping and a constrained approach for areal gridding. The resulting composite corner-point grid (CCPG) has many of the advantages of unstructured perpendicular-bisection grids in that it can follow major features of the geologic description. Compared with perpendicular-bisection grids, CCPGs have exact alignment of the simulation cells with the geologic model, which will minimize property-scaleup errors, and they may be used without the development of new simulation pre- and post-processing applications. This approach also moves closer to having an Earth model shared between the reservoir engineer and the reservoir geologist: The 3D geologic model will provide the grid on which the high-resolution initialization of the simulation model will be calculated.

The full-length paper details the new statistical approach applied to layer coarsening followed by unstructured vertical coarsening and volumetric coarsening.

Layer Coarsening

Static methods are fast. Unfortunately, they do not predict the appropriate number of layers for a dynamic model. The dynamic model must be tested by simulation and the appropriate number of layers determined by trial and error.
Erha and Erha North Development
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18655, "Erha and Erha North Development: Overview," by T.C. Parker and A. Sofidiya, SPE, ExxonMobil, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.

In March 2006, ExxonMobil affiliate Esso E&P Nigeria started production from the Erha deepwater development approximately 97 km offshore Nigeria in 1200 m of water. The Erha development includes Erha North, a satellite development that came on stream in September 2006. The Erha and Erha North Project consists of 32 subsea wells tied back to a floating production, storage, and offloading (FPSO) vessel. A catenary-anchor-leg-mooring (CALM) buoy is used for crude-carrier docking and product transfer.

Introduction

The first exploration well, Bosi-1, was drilled on the block in 1996. The Erha oil discovery was made with the Erha-1 well in February 1999. Appraisal well Erha-2 was completed in November 1999, and the Erha-3 appraisal well and sidetrack were completed in September 2001. Well Bosi-2 discovered oil in March 2002. After the start of Erha development drilling, an oil discovery was made in March 2004 with Well Erha-7 and Erha-7 sidetrack, leading to the addition of a third drill center, Drill Center North (DCN). Recoverable reserves are estimated to exceed 7.9×107 m3 of oil.

The Erha and Erha North plan included sequential startup of three drill centers, managed simultaneously with a two-rig development-drilling program and ongoing production operations. The subsea wells are connected to a new-build, spread-moored FPSO through flowlines and steel catenary risers (SCRs). Processing facilities installed on the FPSO handle 3.3×104 m3/d of oil, as well as provide injection capability for 2.4×104 m3/d of water and 9.6×106 std m3/d of gas. Processed crude oil is stored in the FPSO and periodically offloaded to trading tankers through a CALM offloading buoy.

Development Planning

Initial development plans focused on selecting a development concept for the Erha field N4 resource with flexibility to accommodate future tiebacks to commercialize additional discoveries on the block. The development concept captured and incorporated learnings from ExxonMobil's worldwide project execution, with particular emphasis on other west Africa projects, technology, and operability.

The original Erha full-field development plan included 24 subsea wells, clustered in two drill centers: Drill Center East (DCE) and Drill Center West (DCW). All subsea wells would be drilled and completed from a mobile offshore drilling unit (MODU) and tied back to the FPSO. Producing wells would be brought together through manifolds with insulated flowlines and risers connecting the manifolds to the FPSO. All gas-injection wells would be over the gas cap from DCE, and water-injection wells would be from DCW. Injection wells at each drill center would be routed through a manifold connected to the FPSO with a single uninsulated flowline and riser.
Global Optimization and Uncertainty Assessment for History Matching the Valhall Field
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 100946, "History Matching of the Valhall Field Using a Global- Optimization Method and Uncertainty Assessment," by B.R. Al-Shamma, SPE, Imperial College, London, and R. Teigland, Total E&P Norge, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

A study was made of a global-optimization method to history match a complex reservoir model. Evolutionary algorithms (EAs) were applied, and methods for improving the convergence of the optimization cycle were used. Sensitivity parameters, correlations, and parameter trends were identified in a global search space, and an uncertainty assessment of the most recent history match was carried out with an experiment-design matrix.

Introduction

The focus of this study was to assess the Valhall field reservoir-simulation model by use of EAs and uncertainty assessments to improve the manual history match of the model. The Valhall field is complex with rock compaction as the main drive energy, which contributes to many challenges, including the reduction of porosity (Ø) and permeability (k) with time and continued change of reservoir thickness caused by the compaction. The compaction can affect different parts of the reservoir differently. For example, the reduction in the pore volume can vary between regions, resulting in problems with the history-matching process in which changing a particular parameter can have opposite effects on wells or regions. Fig. 1 shows the workflow used for uncertainty assessment.

The Valhall field is an oversaturated Upper Cretaceous chalk reservoir in the North Sea approximately 290 km offshore Norway in 69 m of water. Discovered in 1975, oil production began in 1982. Oil originally in place was estimated at 4.3×108 m3. Total production at the time this paper was written was 7.9×107 m3 of oil equivalent. The primary reservoir is the Tor formation, with a secondary reservoir in the Hod formation. The thickness of the Tor formation varies, abruptly ranging from 0 to 80 m. Approximately 50% of the drive to date has been from rock compaction, observed by porosity reduction in infill wells. The porosity is greater than 50% in some places; some fractured permeability exists, but matrix permeability is low (less than 10 md). The average solution-gas/oil ratio (GOR) for the field is approximately 20 std m3/m3, with an increase in the field GOR after 20 years' depletion of only 35%. The main challenges experienced during drilling and production included chalk and solids production, well failures and stability problems, fracture closure during depletion, and a subsiding seafloor around the original production platform.
Improved and More-Rapid History Matching With a Nonlinear Proxy and Global Optimization
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101933, "Improved and More- Rapid History Matching With a Nonlinear Proxy and Global Optimization," by A.S. Cullick, SPE, W.D. Johnson, SPE, and G. Shi, Landmark Graphics, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

Generating reservoir-simulation models that match field production data has been a long-time industry challenge. Two workflows are presented for assisting history match. One workflow minimizes the misfit between simulated and historical data with a global optimizer. Another workflow trains a comprehensive nonlinear-proxy model with a small set of numerical simulations from experimental design to reduce the number of numerical simulations.

Introduction

History matching is, by its nature, an ill-posed optimization problem with many unknown reservoir parameters that could be adjusted to achieve a match against a relatively small amount of measured data at wells. The most common method of history match is to execute many simulations one at a time, changing a few parameters in a trial-and-error fashion. Often, a reservoir-simulation history match might require months of effort and many simulations to achieve a single model that neglects model nonuniqueness and often may not be a good predictor of future field performance.

Many automated history-match algorithms have been investigated. Early assisted history matching emphasized deterministic gradient-optimization algorithms that require complete derivatives of the production response with respect to reservoir parameters. Subsequently, the emphasis evolved to faster methods to compute the sensitivity coefficients, such as streamline simulation, with emphasis on preserving uncertainty through the integration of geostatistics. Recent developments with adjoint models have renewed interest in sensitivity-based algorithms. However, none of these methods have been taken up widely by practitioners.

With black-box optimization, the number of required simulations to achieve a match can be very large, numbered in the hundreds of simulations. If a single simulation model takes many hours to execute, there is good incentive to reduce the number of simulations for the optimization, even with the use of a distributed-computing system.

This study used a global optimizer, while seeking to reduce the number of simulations with a fast proxy model. The use of proxy-regression models has been suggested to reduce the number of required simulations, but analytical-response models may not be sufficiently robust to represent the nonlinear reservoir production and pressure vs. time profile data. The use of neural networks as nonlinear-proxy models also has been suggested. In this paper, a history-match workflow is presented that has a robust, nonlinear neural-network proxy model to improve a history match and reduce the number of finite-difference simulations required.
Techbits: Recent Horizontal, Multilateral Well Trends Examined in Workshop
Authors: JPT staff _
Published: February 2015

Techbits

More than 85 attendees converged on Merida, Mexico during 27–28 February for SPE's Applied Technology Workshop (ATW) titled "Horizontal and Multilateral Wells." The international audience of operators, service-company representatives, and academics explored the multidisciplinary nature of developing and managing these wells and the ways to maximize their design, drilling, and completions processes. Over eight sessions, the workshop covered a range of topics, including an overview of the technology; geology and geoscience concerns; reservoir performance and modeling; understanding the wellbore and its effect; drilling, completion, and stimulation practices; economic and risk analysis of the technology; and future challenges.

ATW Cochairpersons Benito Ortiz of Pemex E&P and Ding Zhu of Texas A&M University chaired the first session, which focused on the current state of the art in horizontal and multilateral wells planning. Ortiz gave the opening presentation, reviewing his company's approach to horizontal and multilateral technologies. His overview addressed the importance of horizontals and multilaterals to Pemex and to the industry as a whole. Ortiz stated that "the easy oil in Mexico is over," which is the driving force for the application of the new technology. He emphasized that horizontal and multilateral wells employ multidiscipline-oriented technologies, and that successful implementation will require communication and mutual understanding between each member of the project.

Chevron's Julie Bonner presented a revealing summary about the history and status of worldwide multilateral well applications. Bonner stated that high oil prices coupled with reserves availability and accessibility challenges have accelerated the implementation of horizontals and multilaterals. The efficiency and profitability of many of the technologies developed for these wells strongly depend on reservoir characteristics, and Bonner emphasized that people, planning, and proper implementation are key issues in the development of the required technology.

Bonner also chairs the Technical Advancement of Multilaterals (TAML) committee, which set up a classification system for multilateral wells based on the amount and type of structural support provided at the junction of a multilateral. The TAML Level-3 junction, in which the main bore is cased and cemented and the lateral bore is cased but not cemented, is the junction of choice in the industry because of its flexibility for both new and existing well applications, its openhole support, and its ability to support multiple laterals.
Technology Insertion: Pure Play or Witches' Brew?
Authors: Holland Dutch , Skarke Gary
Published: February 2015

Management

It has been said that running a business is easy; all you have to do is buy some stuff, sell some stuff … and that is all there is to it … except for a few million details. It might also be said that inserting new technology is simple; all you have to do is buy/build some software and then implement it … and that is all there is to it, except for a few million details.

Tongue in cheek? Of course, but there is nothing tongue in cheek about inserting new digital energy technology into upstream assets while production is running flat out. While much of the technology holds great promise, the difficulty in implementation is much more complex and difficult than imagined.

Technology can be a real problem solver only if two conditions are met: the technology must work and it must be successfully implemented in upstream business units. During the rollout, the workable technology system must be made ready for users, and users must be made ready to use the new technology. Simple? Not really. Industrywide, many technology insertions continue to be highly problematic, producing disastrous results.

Why? Primarily it is that one "deadly" word that inevitably breeds widespread confusion: implementation. The truth is that there are two legitimate, but very different, ways of getting new technology into play—deployment and adoption. Both ways require different actions and generate different reactions and results. Consequently, when people are not clear whether implementation means deploying or adopting a particular technology, be prepared for a technology insertion failure.

Consider how these pure, very different, very technical rollout strategies are defined. When management decides a technology will be good for the company and mandates that all units use it for business operations by a specific date, that is a "deployment" or taking an action requiring others to respond. Imagine the chief of operations of an airline saying to pilots that the new engine-start procedure is to be used for all engine starts beginning Monday morning at 0800 hours. That is a deployment.
Technology Focus: Deepwater Exploration and Production (June 2008)
Authors: Olson Karen
Published: February 2015

Technology Focus

The technical challenges of deepwater development cross all disciplines and all phases of a deepwater field's life. It starts with the explorers, who interpret subsalt images to locate potential fields hidden below thousands of feet of salt at depths reaching the current limits of our rigs. It continues with the drillers, who are drilling faster and deeper and collecting critical data to help subsurface engineers appraise the size of the field. Additionally, they provide a stable wellbore that enables the completion engineer to complete the well with little-to-no formation damage and possibly stimulate the formation with reliable downhole equipment. Finally, subsea and facility experts step in and install subsea and surface kits (depending on whether the completion is wet, dry, or hybrid) designed to handle a range of the field's conditions.

Long-term production from deepwater fields has been a challenge and will become even more challenging with respect to being able to produce wells at high rates initially and recover the maximum reserves. Producing beyond primary depletion will require the use of artificial lift (e.g., gas lift or electrical submersible pumps in the well or at the mudline) and reservoir-pressure maintenance (either natural or artificial) and, possibly, enhanced oil recovery.

As we continue to explore in deep water, new horizons at depths never before completed are demanding development of new ideas and new technologies. As professionals working in the oil industry, we need to continue working together to come up with new ways to develop these deeper high-pressure reservoirs; we need to keep that "can-do" attitude.

Deepwater Exploration and Production additional reading available at the SPE eLibrary: www.spe.org

SPE 110089 • "Calibrating the Mechanical Properties and In-Situ Stresses Using Acoustic Radial Profiles" by Colin M. Sayers, SPE, Schlumberger, et al.

IPTC 11282 • "Planning a Deepwater Well for All Seasons: Platina-2, a Combined Appraisal/Development Well" by Ian Brown, BP plc, et al.

SPE 112472 • "Meeting the Flow-Assurance Challenges of Deepwater Developments: From Capex Development to Field Startup" by M.M. Jordan, SPE, Nalco, et al.

SPE 111629 • "Techniques for Monitoring the Recovery of Deep, Cold-Water Habitats Following Physical Disturbance From Drilling Discharges" by Daniel O.B. Jones, National Oceanography Centre, et al.
Subsea Gas Lift in Deepwater Applications
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18820, "The Use of Subsea Gas Lift in Deepwater Applications," by Subash S. Jayawardena, George J. Zabaras, SPE, and Leonid A. Dykhno, Shell Global Solutions, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

Riser-base gas lift is used in subsea developments for production enhancement. It is an effective method to suppress severe slugging that occurs in flowlines with downhill inclination. In some cases, gas lift can aid blow-down for hydrate prevention. Gas lift is not always needed because its effectiveness depends on reservoir performance, fluid properties, seabed terrain, subsea architecture, and flowline and riser specifications. The need for gas lift, optimal operability, and system design should be assessed from various aspects, including flow assurance. A generic set of guidelines was developed on the basis of past experience with riser gas lift applications for different deepwater subsea projects and associated multiphase-flow phenomena.

Introduction

This paper discusses riser-base gas lift for deepwater subsea oil-production systems. The focus is how flow-assurance concerns affect various engineering decisions in designing a gas lift system. Riser-base gas lift is injection of a predetermined rate of gas from the host facility into the production flow-line (riser) at the seafloor. The reasons for gas lifting can vary, but the most important pertain to flow assurance, production enhancement, flow stabilization, and flowline depressurization.

Why Gas Lift Is Needed

The stages of a field's life should be studied to determine when to install and operate the gas lift system. Gas lift is not always beneficial; in some cases, increasing the gas rate may be detrimental to the performance of the subsea system.

Production Enhancement.

Gas lift for production enhancement lowers the flowline pressure. Typically, gas lift is needed with high water cuts in the flowlines, low-GOR fluids, and low-to-moderate production rates. The effectiveness is higher in systems with low production-system-inlet pressures. One major advantage of gas lift for production enhancement is that there are no moving parts in the subsea system, apart from valves and chokes. Compression for gas export is almost inevitable in any subsea development; therefore, the supply of lift gas during production is not a major issue.

When to use gas lift for production enhancement should be determined by use of integrated (reservoir/wells/flowline) production modeling. The study also should include the water/gas injection to the reservoirs. Accuracy of flowline/riser pressure-drop and liquid-holdup calculations in multiphase-flow models and the accuracy of pressure/volume/temperature predictions are crucial. This accuracy becomes more important in larger-diameter flowlines with deepwater risers in which the multiphase behavior is different from that in smaller-diameter systems.
Through-ESP Stimulation: A Cost-Effective Alternative
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112315, "Through-Pump Stimulation: A Cost- Effective Alternative," by K.I. Ojukwu, SPE, Petroleum Development Oman, prepared for the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 13–15 February. The paper has not been peer reviewed.

A major disadvantage of electrical submersible pumps (ESPs) is that they block access to well re-entry for surveillance and through-tubing intervention. One case of the latter is acid stimulation. In Petroleum Development Oman (PDO), acid jobs have been carried out as part of work-overs to retrieve the pumps first. The cost implication can be large, ranging from USD 250,000 to 400,000. Two deployment techniques were adopted in PDO recently, bullheading acid into the reservoir through an ESP and spotting acid through coiled tubing (CT) into the reservoir; by so doing, 80 to 93% of comparative cost was saved. The techniques involved the use of abrasion-resistant ESPs for vertical wells and an ESP bypass (Y-tool) for CT deployment in horizontal wells.

Introduction

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

Game Change

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

President's column

The world is still in a crisis, and SPE is beginning to see consequences. Some of our conferences and workshops have seen fewer attendees. However, membership growth doesn't seem to be affected much.

Financial crises are strange creatures. When I visited the Vietnam Section in April, section secretary Ben Gedge made a very wise observation. He said that most of us can live very happily without buying anything new for the next 2 years. However, if we do that, he said, of course the people who manufacture those new things have less income and they will also delay buying "new things," which will cause the global economy to continue its downward spiral, and there is your crisis. This is exactly what is happening at the moment. Many of our members’ companies are "managing" costs by delaying expenditures, including those for learning/networking events like our conferences and workshops. This is a dangerous path, as it will create a downward spiral in knowledge dissemination, where knowledge and global cooperation is key to our industry if we want to continue to provide the world with energy when demand picks up. SPE therefore is trying to break this spiral in a number of ways and has taken a number of actions, mainly to reduce need for travel for members.

One example was piloted in the Gulf Coast Section's recent Digital Energy Conference in Houston, where we held a parallel conference in Second Life. Instead of being there physically, the authors presented their papers "virtually" via the Internet, through their avatars in Second Life. The Second Life conference was presented to the audience in Houston on a big screen.

In March, we used Webex and Skype to bring a presenter in Colorado, USA, to workshop attendees in Queensland, Australia. Remote presentations with interactive audience participation were also done at our May workshop on IOR Petrophysics in Cairo. No visitors yet in a "virtual presentation room," but that could be the next step.

Second, SPE will also bring meetings/workshops/conferences closer to where the members are. So, we will hold very few conferences in fancy places, and, if practicable, more in major industry centres like Amsterdam, Aberdeen, Houston, and Kuala Lumpur.

Third, we will webstream key presentations from large conferences, so that anyone can follow the presentations in his/her own office on the computer screen. More innovations may come, and I am open for suggestions.

In the long run, conferences and workshops without real people will not be easy to sustain, as building a network is an important aspect of those events. However, we believe that for the next 1 to 2 years this will work and we will put a lot of effort into finding new ways to bring people together, such as SPE virtual networks, discussion groups, etc.