bluuebunny/crossref_metadata_2025 huggingface dataset:
Companies Strive To Better Understand Shale Wells
Authors: Rassenfoss Stephen
Published: February 2015

Fracture science

While drilling more than 2,000 wells in the Fayetteville Shale, Southwestern Energy systematically established standards for drilling and completing wells.

Based on the numbers, the company mixes slickwater with a 50:50 mix of fine and coarse grains of sand when fracturing wells in the shale formation. The proppant mix was chosen after a field test comparing 26 pairs of wells where everything, but the sand used, was the same.

It found that generally the 50:50 mix of coarse-grained sand and fine-grained proppant (100 mesh and 30/70 mesh) was more productive than all coarse-grained (30/70 mesh). There was little benefit shown in the five pairs of wells using all of one or the other.

But there were some wells where a mix was used with lower production than the paired well using all coarse-grained sand. Those five with lower output lost less—down an average of 15%—than the 16 wells that benefited from the mix—up an average of 27%.

In the past year, Southwestern has increased its research and laboratory capacity to learn why such things as proppant size matter. “We are now trying to understand what the mechanism really is,” said Karen Olson, completions expert for the Fayetteville Shale at Southwestern, in a presentation at the recent SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas.

Southwestern has been a leader in the way things are done in the shale business. It discovered the second major shale play because of an anomaly—a well had produced many times more gas than it should have based on the size of its reservoir. A small group in exploration ultimately concluded the excess was due to gas seeping up from the Fayetteville formation, which covers a large part of Arkansas.

Southwestern’s system of learning by changing one variable per well in search of better ways has been typical of the industry’s approach to steady improvement. The thinking by Olson and other experts is that shale formations have a lot of upside that can be unlocked with a greater understanding.
Software-Based Deepwater-Blowout- Preventer Testing
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 21688, ’Advances and Effects of Software-Based Deepwater-Blowout-Preventer Testing,’ by C. Mark Franklin, SPE, IPT Global; Tim Sargent, SPE, Noble Energy; Charles Brown, SPE, Hamilton Engineering; Gary W. Owen, SPE, Devon Energy; Steven Griffith, SPE, Shell; Jerry Osmond, SPE, Hess Corp.; Tore Gronas, Statoil; and Rick Cully, IPT Global, prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.

To advance the technology of blowout-preventer (BOP) leak detection through a software-development initiative, operators, service providers, and drilling contractors established an industry consortium in early 2009. The initial development focused on testing BOPs in deep water. Upon completion of the pilot program on five deepwater rigs, the results exceeded original expectations. The test results proved the software effective, efficient, and rig friendly.

Introduction

As drilling moves into deeper water and use of nonwater-based fluids increases, the challenges associated with obtaining effective pressure tests continue to grow. Prevailing interpretations of regulatory requirements to “hold pressure” have been to demonstrate a “flat line” on a pressure chart for a specified period of time. With the relatively low resolution of a circular-chart recorder (CCR), a flat line was produced, essentially, when the resolution of the device was not exceeded (typically 4–6 psi). Also, excessive damping and manipulation would not be recorded.

Joint-Industry Project (JIP)

During 2009 and 2010, four operators, with the support of several service providers and drilling contractors, participated in a JIP. As the main goal, the consortium wanted to develop state-of-the-art leak detection, with best practices for testing BOPs in deep water. The JIP was set up in two phases.

Phase-1 gathered digital data from BOP tests performed in the Gulf of Mexico (GOM) and around the world. Archived data were used as test data, and a library of more than 100 data sets was built. Review of the test results showed that each data set had from 10 to 25 tests, 86% of which represented passing tests.

The data archives provided insight into an automated approach for validating deepwater-BOP pressure tests. A software prototype was developed, along with workflow-automation features, and it was refined through multiple design-review meetings with the JIP members and the US Bureau of Ocean Energy Management, Regulation, and Enforcement.

Phase-2 field-trial installations commenced on five deepwater rigs in the GOM. The software was also run in the background in a real-time operation center during BOP and manifold testing from multiple rig types (i.e., deepwater, tension-leg-platform, and jackup). The goal of Phase-2 was to validate the software and repair software issues.
Santos Basin, Brazil: Successful Drilling Campaign 2008-2010
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22336, ’Case History: Performance of a Drilling Campaign in the Santos Basin, Brazil, 2008-2010: A Success Story,’ by Humberto Carrizo, Giovanny Ortuno, and Tarcilio Dutra Neto, Repsol Sinopec Brasil S.A., prepared for the 2011 Offshore Technology Conference Brazil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed.

The evolution in well design and continuous-improvement actions are reported for the execution of five shallow-water and deepwater wells drilled by Repsol using a third-generation semisubmersible rig during 2008–2010. As part of the continuous-improvement approach, the quality-assessment/quality-control (QA/QC) procedures were tightened throughout the campaign. The proper use of after-action reviews at the completion of each well phase was paramount for the lessons learned from each well and their application to subsequent wells.

Introduction

The exploration-drilling campaign during 2008–2010 in the Santos basin used a moored semisubmersible drilling rig and was the first campaign in Brazilian waters by Repsol Sinopec Brasil. The blocks where these operations were performed are approximately 180 naut miles from the shore base. These wells were post-salt prospects in shallow and deep waters. The map in Fig. 1 shows the well locations for Wells A, B, C, D, and E. In the lower right of the figure is the order in which they were drilled, together with the respective water depth. The complete paper details well design and well operations from spud to total depth (TD).

Actions considered key for performance achievements are framed by a continuous-improvement process, with tangible actions to reduce total time on well, and can be summarized as in Fig. 2. The total time on well can be reduced within the two stages of the well-construction process.

During well planning: Make well-design improvements and/or plan application of a new technology.

During project execution: Make well-operation improvements to remove invisible lost time (ILT) and reduce non-productive time (NPT).

Well Planning

Well-design activities carried out by the multidisciplinary project team are governed by the company’s well-construction process (WCP). The WCP is a gated four-phase process: visualization, conceptualization, definition, and execution. At the end of each phase, a gate-event meeting occurs in which a multidisciplinary technical team, based at headquarters, appraises information from the phase and then, depending on the results, decides whether to continue to the next phase.

The WCP receives well data from the geological and geophysical team, and these data are essential input for well-design activities until the well design is fixed at the second gate and the basis of design is delivered. Design activities end with the drill-well-on-paper document. At the third gate, the drilling program is signed as the main deliverable before starting well operations.
Hybrid Rotary Steerable System Delivers Higher Build Rates and Smoother Holes
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

Every drilling engineer’s dream would be to deliver more complex well profiles and smoother, more consistent boreholes in less time—ideally in a single run—eliminating the need to trip out of hole. The problem is that conventional positive displacement motors (PDMs) and rotary steerable systems (RSS) both exhibit limitations in different drilling scenarios.

Industry Challenges and Needs

Downhole motors, for example, are capable of delivering reliable, very high dogleg well profiles. However, because the drillpipe alternates between rotating and sliding, rates of penetration (ROPs) are low and hole quality is tortuous, increasing the potential for stuck pipe.

On the other hand, fully rotating RSS deliver smoother wellbores at higher ROPs than PDMs, reducing drilling time by as much as 50%. However, the maximum build rate of a typical RSS is only 6 to 8 deg/100 ft, and much lower while drilling soft formations, enlarged holes, or hard interbedded stringers at high angles to the wellbore. For well profiles with high build rates, an RSS may be used for the vertical and lateral sections while motors must be used between the kickoff and landing points. This requires at least three bottomhole assemblies (BHAs) and multiple trips out of hole.

To reduce risks while saving rig time and costs, drillers would prefer the hole quality and performance of an RSS combined with the high dogleg capability and steering assurance of a PDM.

To meet operators’ growing needs both in unconventional shales and difficult formations, Schlumberger developed the PowerDrive Archer high build-rate RSS. In a single run, the technology can deliver well profiles previously possible only with motors. By improving borehole quality and reducing tortuosity, it minimizes the risk of stuck pipe and facilitates the deployment of casing, sleeves, and completion equipment (Fig. 1). It can perform openhole sidetracks and drill deeper before kickoff than other RSS, maximizing reservoir exposure and increasing potential production.

Description, Development, and Deployment

The high build-rate RSS represents a breakthrough in steering control. The RSS has been in use since the late 1990s. However, it could not deliver the 8-to-12-deg/100-ft build rates necessary for typical well profiles in unconventional shale plays. Due initially to rapid increases in shale drilling, Schlumberger began development in 2007 of a new RSS aimed at roughly doubling the maximum build rate of previous tools.
Technology Focus: Natural Gas Processing and Handling (April 2013)
Authors: Hobbs George
Published: February 2015

Technology Focus

On the 201st anniversary of the founding of the first commercial gas operation, the Gas, Light and Coke Company (later British Gas), the future for natural gas has never looked better.

In 2011, global natural gas reserves increased to the equivalent of approximately 80% of oil reserves. Unconventional gas sources are now a large proportion of US natural gas supply, particularly tight and shale gas (30%) and coalbed methane (CBM) (6%). Natural gas in 2011 contributed 24% of worldwide energy consumption, compared with 33% for oil and 30% for coal. CBM is also an important source of energy, particularly in eastern Australia, where three CBM liquefied natural gas (LNG) plants are under construction and a fourth and possibly a fifth are proposed. CBM and Western Australian conventional gas are set to make Australia the largest LNG exporter in the world within 5 years.

Gas is likely to dominate energy supply because of improved available reserves, lower carbon intensity, lesser environmental footprint, and long-term zero-carbon goals involving CO2 capture and sequestration. In addition, removal of contaminants such as water, hydrogen sulfide, and mercury has been improved through nano and smart technologies. Safety improvement research and development is another key objective of the industry.

Underground gas storage is now in greater usage for supply security, with smart wireless technology becoming increasingly involved in its management.

Six floating LNG offshore production facilities are expected to come on stream within this decade, five in Australasia and the other in offshore Malaysia.

The potential is for very remote deep small offshore gas reserves to be economically exploited using floating compressed natural gas (FCNG) technology. Because of the massive effect of US unconventional gas production on LNG imports, gas producers such as Trinidad are reportedly reviewing their future gas export strategies and considering FCNG.

Commercial exploitation of the known massive methane hydrate reserves is still some time off. However, research in hydrate control is advancing the understanding of hydrate physical chemistry. This research also has helped conventional deepwater gas production where subsea/downhole heating now is used to prevent hydrate blockages. Early last year, the US and Japan successfully completed a field trial of methane production from hydrates on the Alaska North Slope.

To find out more, attend the Offshore Technology Conference in Houston, 3–6 May 2013.

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

SPE 161583 The Optimization of Natural Gas Transportation by Michael J. Economides, University of Houston, et al.

SPE 162938 Gas Transmission Market: New Trends Around the World by Gina Vega Riveros, Reservoir Consultant

SPE 151161 Control Loop Performance Management To Improve Business Objectives by Zhenhai Liu, ADGAS, et al.
25,000-psi 500°F Packer-Seal System
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159182, ’A Completion-Technology Milestone - The First 25,000-psi 500°F Packer-Seal System,’ by James Doane, Guijun Deng, SPE, and Scott Collins, SPE, Baker Hughes, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.

As operators continue to drill into deeper and more-extreme formations, the demand for technologies suited to these environments increases. Much effort has been invested across the industry to overcome obstacles in developing safe and reliable completion tools that are qualified for conditions in excess of 15,000 psi and 450°F. A technological milestone was set recently in packer-seal-system development―the first 25,000-psi, 500°F packer-seal system.

Introduction

The criteria for designating fields as high-pressure/high-temperature (HP/HT) fields have changed over the years. Early on, HP/HT fields were those with pressures greater than 10,000 psi and temperatures higher than 300°F. During the last 20 years, the HP/HT designation changed to 15,000 psi and 350°F, an environment in which technical operational challenges have been mostly overcome. Other terms have come into use to designate new HP/HT thresholds. Extreme-HP/HT fields have pressures up to 20,000 psi and temperatures up to 450°F, and ultra-HP/HT fields have pressures up to 30,000 psi and temperatures up to 550°F.

High gas prices and the search for hydrocarbons in deeper formations are key drivers for development of new HP/HT completion technologies. Extreme-HP/HT wells are being drilled in the Gulf of Mexico, on the shelf and in deep water. Many of them have a total depth of more than 25,000 ft and exhibit reservoir pressures approaching 20,000 psi and temperatures exceeding 450°F. There is limited availability of specialized tools for these pressures and temperatures. In ultra-HP/HT environments, there are many technical difficulties that must be overcome, including seals and polymers, metallurgy, and test facilities.

Concept Design

The objective of this project was to design a sealing system for a packer for 7.625-in., 51.2–52.8-lbm/ft casing. The sealing system must be rated to 25,000 psi at 500°F. Qualification testing was conducted with nitrogen to all rating-envelope points at 500°F with a cool down to 250°F. To enhance performance in as-rolled casing and ultra-HP/HT applications, two existing systems were considered for the new seal design. System A is rated to 15,000 psi and 350°F. System B is rated to 15,000 psi and 500°F. In addition, the System-A packer has been qualified for applications with grooved or poor conditions on the inside diameter (ID) of the casing.
Renewing Mature Shale Wells Through Refracturing
Authors: Jacobs Trent
Published: February 2015

Refracturing opportunities

In what may become Act Two for the North American “shale revolution,” some operators are returning to their mature shale wells to refracture, or restimulate, the rock to accelerate the rate of production and enhance the ultimate recovery of trapped hydrocarbons. Refracturing is not a new technique and has been applied for many years in tight rock and vertical wells. But now producers want to apply refracturing to a large inventory of unconventional wells suffering from low production because of ineffective initial completions. Refracturing could also serve as a countermeasure against the characteristically steep decline rates of shale wells. A few years after coming on-stream, most horizontal shale wells produce at a fraction of their initial rate, yet large volumes of oil and gas remain in the rock that could be produced through refracturing.

Those involved expect shale well refracturing activity in the United States and Canada to increase steadily as companies figure out how to optimize the mechanics of the operation. Their optimism is based on some early success stories, and the sheer number of possible refracturing opportunities that exist. “Over these next 2 years, the industry will be sharpening their pencils on how and where they are going to (refracture), and then they are going to do it because the potential is tremendous,” said Ibrahim Abou- Sayed, founder of a Houston-based company called i-Stimulation Solutions that offers upstream engineering and consulting services.

However, some companies are sitting it out until newer technology overcomes some of the challenges involved with refracturing to make it an easier operation to carry out. Tim Leshchyshyn, founder of a Calgary-based company called FracKnowledge that maintains a database of fracturing information, characterizes refracturing as a “large, complicated topic” that needs more research and development to become a reliable technique. “For many of the candidates that need to be refractured, the industry is short on technology to do so,” he said. “I think there are some tools out there that help, but there is still a lot of room for technology development to make it easy and highly successful.”
Testing of Distributed-Temperature Sensing in Flexible Risers and Flowlines
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23948, ’Full-Scale Testing of Distributed-Temperature Sensing in Flexible Risers and Flowlines,’ by Nick Weppenaar, Thomas Iversen, and Bo Andersen, NOV Flexibles, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

This paper presents results from full-scale testing of a flexible riser equipped with embedded sensors for distributed-temperature sensing (DTS). Testing includes monitoring of accessories mounted on the riser, monitoring of hot spots such as trenched sections of the riser, and detection of breaches of the outer sheath. Applications of such a condition-monitoring system to riser-integrity management (RIM) and production optimization are worth examining.

Introduction

With the increasing use of flexible-pipe technology—driven by the move of new offshore fields to deeper, more-marginal, and more-challenging conditions— the need for systematic management of the flexible pipes is becoming more apparent. In particular, the full implementation of RIM plays a vital role in ensuring an efficient and safe operation. Riser-condition monitoring and inspection form an important part of integrity management, together with processing and analysis of the monitored data. In that respect, the recently developed technology within optical-fiber monitoring offers unique possibilities for quantifying the integrity of flexible risers during their service life. The advantage of an embedded monitoring system is the ability to survey the riser condition continuously, thus enabling operators to detect potential damages in a timely fashion. The embedded system will allow monitoring in critical areas (e.g., under a bend stiffener or inside an I-tube) where access is limited for externally mounted monitoring systems.

Temperature-Monitoring System

The temperature-monitoring system is a DTS system that uses a standard multimode optical fiber to measure the temperature at all points along the fiber with a given spatial resolution. The principle of implementation into a flexible pipe is shown in Fig. 1. The fiber is mounted on top of the outer tensile layer while being protected from crushing forces. The specific implementation that has been achieved allows for temperature measurements with a spatial resolution in the longitudinal direction of the pipe of approximately 8 cm. Currently, this can be implemented in pipes that are up to approximately 5 km in length, and the sample time can be as fast as 10 seconds per fiber. If a longer pipe length needs to be monitored, this can be achieved at the expense of spatial resolution or temperature resolution.

For the present series of tests, the fiber length is approximately 200 m, which allows for a high temperature resolution. The system measures every 10 seconds, with a temperature resolution of approximately 0.1°C and a spatial resolution of approximately 15 cm.
Innovative HP/HT Drilling Practices in Malaysia: A Case Study
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166110, ’Successful HP/HT Drilling Through Innovative Practices: Sharing a Case Study of a Deep HP/HT Well,’ by M. Syazwan, SPE, Y. Yap, SPE, L. Umar, SPE, and M.M. Pepple, SPE, Petronas Carigali, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

Despite a short 18-month planning time and very limited geological data, the TTD-1 high-pressure/high-temperature (HP/HT) exploration well in East Malaysia’s Block SK was drilled successfully to its technical limit by adopting innovative practices. Various technical challenges were overcome, including an abnormally steep pressure ramp, high overbalance, and high temperatures.

Introduction

Malaysia has a relatively low number of offshore HP/HT wells drilled by various operators since the 1990s. In the last few years, a series of successful HP/HT discoveries has prompted operators to focus on this area. The major domestic operator began its first HP/HT exploration drilling in 2008.

In the 2012 HP/HT exploration campaign (Fig. 1), the operator of East Malaysia’s SK Block and their partners successfully drilled an HP/HT reservoir at a depth of 4830 m. TTD-1 was the deepest well of its kind drilled by this operator in Malaysia. The undisturbed-pore-pressure estimate was approximately 14,000 psi, with a maximum temperature of 325°F. Significant gas was discovered throughout the target reservoirs.

TTD-1 was the second well drilled in the two-well HP/HT campaign in 2012. The well was spudded on 7 May 2012 and plugged back on 5 November 2012. The well was successfully production tested in both the normal and HP/HT reservoirs.

Well Challenges and Mitigation

This section outlines a number of the issues faced in the drilling of this well. For a full discussion of these issues, please see the complete paper.

Unreliable Offset-Well Data in HP/HT Section. The availability of reliable data up to the start of pressure ramp helped the planning of the non-HP/HT section. For the HP/HT section, there were no data in any of the surrounding wells that could help in modeling the pore pressure and fracture gradient as inputs for well design. The key challenge was in understanding the overpressure mechanism.
Intelligent-Well Completions in Agbami: Value Added and Execution Performance
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20191, ’Intelligent-Well Completions in Agbami: A Review of the Value Added and Execution Performance,’ by Adekunle Mojeed Adeyemo, Chris Aigbe, Ike Chukwumaeze, SPE, David Meinert, SPE, and Steven Shryock, SPE, Chevron Nigeria, prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May.

Use of intelligent-well-completion (IWC) technology has grown, even with perceived risks associated with installation and longevity of the systems. In the Agbami field, offshore Nigeria, for which 80% of the development wells are planned with IWC installations, understanding these risks was key in justifying IWCs. The methodology used to quantify the realizable value from zonal control and data acquisition and a review of the execution performance for the initial IWC wells are presented.   

Introduction

First production from the Agbami field was 29 July 2008, and it was producing at 140,000 BOPD at the time of writing. Peak production of 250,000 BOPD (not accounting for facilities downtime) was expected by the end of 2009. The Agbami field, discovered in 1998, is 70 miles offshore Nigeria at a water depth of approximately 5,000 ft.

The field is a northwest/southeast-trending doubly plunging anticline, with a significant thrust fault through the crestal axis of the structure. As Fig. 1 shows, the field has four main reservoirs: 17MY, 16MY, 14MY, and 13MY. Approximately 80% of the field in-place volume and reserves are in the deepest sand (17MY), having average porosity of 18% and average permeability of 270 md.

The field-development plan has 38 subsea wells (including 20 producers, 12 water injectors, and six gas injectors) tied back to a floating production, storage, and offloading (FPSO) vessel through subsea flowlines. The drilling-and-completion program is spread over three development-drilling stages. The project is in Stage 1, with eight producers and two gas injectors on line. Pressure maintenance will be by peripheral water injection and crestal produced-gas reinjection to ensure compliance with a “no flare” policy.

Geologic and Engineering Considerations

The field has multiple lobes within each major reservoir. Although these sand lobes, or zones, are in pressure equilibrium geologically, the vertical/lateral connectivity under dynamic conditions is uncertain. Therefore, waterflood and gasflood fronts are likely to advance through the reservoirs at different rates, leading to conformance issues. To optimize field performance and recovery, IWCs with downhole control valves are installed in the Agbami wells. The system will provide zonal information and control of production from and injection into the completed subreservoir zones. IWCs will enable zonal production/injection management for optimal field development and oil recovery.
Technology Focus: Wellbore Tubulars (May 2010)
Authors: McDonough Casey
Published: February 2015

Technology Focus

Shortly after the invention of gunpowder came the invention of the cannon. The first cannon barrels were made of paper and bamboo. Accuracy and distance requirements forced the refinement of the 13th-century cannon to the artillery guns of today. The first refinements came from incorporating different materials. The bamboo was replaced by iron. Other refinements came from shaping and treating the materials. As iron-working techniques developed, so did the cannon. Early cannons were cast with a bore, and then bores were machined. Smooth bores were replaced with rifling to further improve the accuracy of the projectile exiting the cannon. Through the centuries, material science and machining techniques were required to manage the rapidly expanding gas in a tube to propel projectiles to combat an enemy. See the parallel in our industry?

The use of different materials and techniques to combat physical and economic restraints of drilling and completing complex wellbores is the obvious theme of 36 papers reviewed for this feature. Recurring themes include applications for expandable casing, the use of unconventional tubular materials for drilling and completion operations, and combating corrosion. A majority of the articles covered extended-reach and horizontal applications. Modern drilling and completion technology depends critically on the availability of advanced materials and on tailoring these materials with a desirable set of structural and functional properties.

Many times, the use of new materials and technology solves some of the problems facing our industry. But many times, the solution is application of existing materials and technology in an innovative way. Of particular interest in my organization is tubular technology that may have merit in the vast domestic unconventional shale plays. Can different materials be used to reduce torque and drag while drilling and still provide the benefits of conventional methods? Can we squeeze more performance out of smaller rigs? And finally, can expandable casing be used to recomplete or restimulate an existing wellbore?

Wellbore Tubulars additional reading available at OnePetro: www.onepetro.org

SPE 120084 • “Effects of Friction on Post-Buckling Behavior and Axial-Load Transfer in a Horizontal Well” by Guohua Gao, SPE, University of Tulsa (now with Shell), et al.

SPE 126515 • “Influence of Relevant Parameters on Hole Cleaning and Pipe-String Erosion in Air Drilling” by Hongjun Zhu, SPE, Southwest Petroleum University, et al.

SPE 120542 • “Successful Application of Extra-Long Expandable Cased-Hole Liner Remediates Production Well” by Riyadh Al-Barghawi, Saudi Aramco, et al.
Deepwater Workover Experience With Extreme Hydrostatic Overbalance
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 134378, ’Deepwater Workover Experience With Extreme Hydrostatic Overbalance, 2002-2009’ by G. Myers, SPE, D. Cahill, SPE, P. Clay, SPE, B. Esquinance, B. Smith, SPE, and R. Zeringue, SPE, Shell E&P Co.; C. Davis, SPE, Shell International E&P; and T. Kenney, Crown Consulting, originally prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September.

The full-length paper presents planning and execution details for fluid-loss control during workovers with “extreme-hydrostatic-overbalance” (EHO) conditions (i.e., between 1,500 and 4,000 psi). Actual results for several wells from three deepwater fields in the Gulf of Mexico (GOM) are included. The information is applicable to operators that face similar requirements to maintain well control throughout the workover, mitigate any damage to the installed sand control or reservoir, and complete removal of the fluid-loss barrier to re-establish production.

Introduction

For many years, the industry has dealt with large hydrostatic overbalances in a variety of ways during workovers. Onshore, operators of tight gas fields initially may pump fluid to kill the well for rig up, then add fluid intermittently during the job as required to work safely. Offshore, operators of shallow-water, higher-permeability fields may initially kill the well with seawater for rig up, then continuously feed or “let the well drink” seawater to maintain hydrostatic overbalance during the job. The full-length paper focuses on direct-vertical-access (surface tree) wells in deepwater GOM fields. These wells are characterized by high-permeability, thick sand intervals; downhole sand control; and very high fluid-loss rates after perforating or stimulation. Profitability is tied to maintaining high production rates without significant solids production. It is the combination of extreme hydrostatic overbalance, high permeability, downhole sand control, and high production potential that makes these wells so challenging. Subsea wells in deepwater GOM fields must be handled differently because of the potential for riser collapse, use of riser fill valves, and the daily cost of floating rigs.

EHO is a term used to describe conditions significantly outside the normal. It is common to execute workovers in the GOM with 200- to 300-psi hydrostatic overbalance—that is, the difference between the hydrostatic-column pressure at the perforations and the near-wellbore reservoir pressure. Depending on the reservoir-drive mechanism, workovers in later life may be executed with 300- to 800-psi hydrostatic over-balance (moderate) or 800- to 1,500-psi overbalance (high). The term EHO is used to describe wells with 1,500-psi or greater overbalance and is not a precise definition. Depending on the job, 1,200-psi hydrostatic overbalance may require similar planning. To date, jobs have been planned with overbalance approaching 4,000-psi, typically using seawater as the workover fluid.
Parque das Conchas (BC-10) - Delivering Deepwater Extended-Reach Wells in a Low-Fracture-Gradient Setting
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20608, ’Parque das Conchas (BC-10) - Delivery of Deepwater Extended-Reach Wells in a Low-Fracture- Gradient Setting,’ by Wouter Bode, Robin Hartmann, and Andrew Kenworthy, Shell Brazil, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

Delivering wells capable of high production rates and high ultimate recovery of heavy oil is a key requirement for the ultradeepwater Parque das Conchas development in Block BC-10, Campos basin, Brazil. The well design presented here achieved these objectives while confronting key challenges including the shallow reservoir and the low-fracture-gradient setting.     

Introduction

Block BC-10 is approximately 120 km southeast of Vitoria off the coast of Brazil. Water depths range from 1400 to 2000 m. A total of 14 exploration and appraisal wells had been drilled at the time this paper was written. Five oil accumulations were discovered and appraised in Block BC-10. In June 2006, field-development plans were submitted for the Ostra, Abalone, Argonauta-BW, and Argonauta-ON fields. Phase 1 of the project comprised development of the first three fields. Argonauta-ON is part of Phase 2. A combination of long horizontal wells and artificial lift is required to deliver and maintain economic rates.

Phase 1 of the drilling and completion campaign began in April 2008 from the mobile drilling unit. As of December 2009, six horizontal producers and one vertical gas injector at Ostra, one deviated producer at Abalone, and two horizontal producers at Argonauta-BW had been drilled and completed.

Well Design

Well-design work commenced in 2005. The key challenges of the well design were as follows.

3D nature of the wells with the fixed subsea layout and revised subsurface horizontal entry points

Shallow reservoir below mudline and a limited pore-pressure/fracture-gradient-pressure ratio

Unconsolidated reservoir sands with highly nonuniform sands and large packages of shales

Low reservoir temperatures with high in-situ fluid viscosities

Stratigraphically complex and faulted reservoirs

Screen selection to produce safely without a full gravel pack

A production screen test of the drilling fluids to provide sufficient hole-cleaning rheology and shale inhibition while drilling the target reservoir

To deliver wells capable of high rates over a long life, the base design required long horizontal wells with sand control. It should be noted that these wells are classified as extended-reach wells because of their shallow reservoir entry.
Resistivity, Imaging-While-Drilling Tool Helps Well Placement in Chinese Tight Reservoirs
Authors: Gang Lv Zong , Run Peng Hai , Li Yang Jin , Qiang Zhang Shi , Halomoan Parlindungan Monris , Zhao Jack , Yang Liu , Ha Stephanie Chow Yuk , Denichou Jean Michel
Published: February 2015

Technology Update

Two case studies describe the use of a new resistivity and imaging-while-drilling tool that was used to improve well placement in the Sichuan Basin of central China—a drilling environment presenting high levels of geological uncertainty. The first case involved the technology’s application in a very thin tight dolomite gas reservoir, and the second case involved the first commercial development well in the region to target a carbonate oil reservoir. In addition to assisting well placement, the technology enabled valuable information about the natural fracture network to be obtained to support the completions design.

Background

The Sichuan Basin holds the biggest gas reserves in China and is the country’s leading gas production region. The basin rests in a major compressional tectonic area, highly compressed and characterized by thrust-faulted anticlines. Modern exploration and production started in the 1950s. Most of the gas and modest quantities of oil are produced from fractured carbonate and low-permeability sand-stone reservoirs.

PetroChina Southwest Oil & Gas Company (SWOGC)—one of the biggest subsidiaries of PetroChina—operates in the basin. It has more than 100 exploration and development concessions in the region, covering a total of 180 000 km2. Natural gas reserves in place are 842.2 billion m3, with estimated recoverable reserves of 320 billion m3.

During the early phases of exploration and development, wells were drilled vertically. Horizontal wells were introduced during the 1990s to enhance production from tight reservoir plays, which include limestone, dolomite, and tight sands. Logging-while-drilling (LWD) applications used for formation evaluation and well placement typically included propagation resistivity, density/porosity measurements, and real-time density image logging.

Today, after more than 20 years of production, most of the thickest tight gas reservoirs have been intensively developed. Since 2011, PetroChina SWOGC has increasingly targeted ever thinner tight gas formations using long horizontal drilling combined with multistage hydraulic fracturing. However, several subsurface challenges needed to be overcome for these efforts to succeed, particularly because of the extensive faults and fractures in the reservoir rock.

To meet these challenges, and enhance reservoir understanding, the company has deployed advanced LWD real-time acquisition and transmission technology providing high-resolution electrical borehole images, azimuthal gamma ray, and multidepth formation resistivity measurements.
Barriers to Implementing a Real-Time Drilling Operations Strategy
Authors: Crawley Charles , Rizvi AiJaz
Published: February 2015

Management

The digital oilfield and real-time operations continue to be the subject of a great deal of emphasis and interest. Although enormous potential has been demonstrated by a few industry bright spots, the development and adoption of the real-time centers seems to be somewhat slow and progressing at a very gradual pace.

This article is based on a survey conducted by the Real-Time Optimization Technical Interest Group (RTO TIG). In conducting this survey, the RTO TIG was interested in the progress being made toward real-time drilling operations with drilling center support. The survey was structured to isolate information about the barriers associated with moving from data acquisition to decision to action. A survey of a subset of SPE members with a drilling interest was conducted to gain an insight into these issues. Understanding where we are and the barriers in the way of where we want to go will help us focus on what must be done.

This article is based on the fifth in a series of SPE papers sponsored by the RTO TIG (see www.spe.org/groups/tigs).

The Survey

The survey was sent by email to a subset of the drilling community with representation from national oil companies (NOC), major integrated oil companies (MIOC), large independents (LI), small to medium independents (SMI), and service companies and consultants (SCC).

The survey recipients were asked to provide their perspectives regarding where along the process they were finding difficulties. In other words, where were efficiencies lost and what caused wasted effort and lost time?

The survey had two focuses:

The first focus was on the overall process of drilling a well, from the initial modeling and well planning to the actual drilling of the well and making decisions and improvements in real time. The effective use of the real-time drilling concept involves the bridging or integration of all steps in the process, including initial planning, data collection, actual drilling, continuous validation of models during the process, and making decisions and taking action based on the real-time data flow (Fig. 1). Although we expected to find snags and bumps in the road, we were pleased to learn that few respondents saw major roadblocks in the path.

The second focus of the survey was on the specific technical steps of the process and the approaches being used during these steps. We were particularly interested in the differences in approach taken by the different operators because the differences may highlight an easier path to implementation.
Unconventional Resources: Cracking the Hydrocarbon Molecules In Situ
Authors: Karanikas John M.
Published: February 2015

R&D Grand Challenges - This is the sixth in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee.The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).

Discoveries of accumulations of light crude oil are dwindling, and known resources are increasingly concentrated in areas that are predominantly accessible by state-owned or state-affiliated energy companies. As a result, the quality of (conventional) crude oil—particularly oil sourced from non-OPEC reservoirs—has been declining. The trend is bound to accelerate as unconventional hydrocarbons such as bitumen are brought into production to satisfy the world’s energy demand, which is expected to increase by slightly less than 50% in the next 20 years.

Because the recovery and surface processing of these heavier molecules is more difficult, it is appropriate to ask whether a portion of the surface processing can be performed downhole (in situ). In fact, in the case of deeper-lying oil shale, it is the only realistic recovery option. There are three approaches by which in-situ manipulation of molecules can be accomplished: biological, chemical, and thermal. Although this article focuses on the thermal route, it should be noted that hybrid recovery methods may be more effective in satisfying the requirement to maximize economic value while minimizing water consumption, emissions, and land usage.

The oil sands of Alberta, Canada, and the oil shale deposits in Colorado contain volumes of hydrocarbons that are at least comparable to the conventional oil resources in the Middle East (Fig. 1). Extraction by open pit mining is the dominant recovery method for commercial exploitation of the oil sands and is the only commercially practiced recovery method for oil shale. However, 70% to 80% of the oil sands in Alberta are deposited at intervals that are too deep (deeper than 60 m) to mine economically, and the same holds true for the richest and thickest sections of oil shale (deeper than 1,000 ft). Ever-increasing concerns about the environmental impact of mining (soil removal, tailings ponds, etc.) provide additional incentives toward the use of in-situ recovery methods.
Overcoming Black Sea Ultradeepwater Drilling Challenges
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 21676, ’Overcoming Black Sea Ultradeepwater Drilling Challenges,’ by Luiz A.S. Rocha, SPE, Edgard G.A. Arduino, SPE, Danilo S. Gozzi, Sandra B. Duarte, Gabriel H. Azevedo, SPE, Luis A.N. Suarez, Jose C.S. Bruno, Bruno C.M. Pereira, and Patricia O.A. Pessoa, Petrobras, prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.

A well-management process that includes design methodology and well-execution procedures was used by Petrobras to drill its first ultradeepwater well in a remote and challenging area of the Turkish waters in the Black Sea (Fig. 1). Ranked as a well of the highest complexity level, this wildcat deepwater well faced a number of expected hazards, such as shallow gas zones, long abnormally pressurized intervals, low-fracture-pressure-gradient sections, lost-circulation zones from the presence of fractured limestone, great potential for false kicks (breathing formation and ballooning), and the possibility of gas migration into the riser. Petrobras also developed a well-classification method that takes into account several factors, including water depth, number of wells drilled in the area, and the existence of abnormally pressurized formations. The main goals of this procedure are to establish the proper well robustness (WR) and to define operations that should be used to mitigate operational problems. Despite all of these challenges, the well was executed according to its original plan, indicating that the method was applied successfully and can be repeated in other wells.

Introduction

The depletion of old oil fields has caused operators to seek new opportunities in previously unexplored areas. The challenges of these new frontiers and the high cost of drilling usually result in expensive wells. These high costs, in turn, may tempt some operators to implement dangerous cost-reduction techniques. These cuts can lead to underestimated well design, which often leads to the loss of the well and the construction of another one. Thus, the cost reduction expected at the beginning becomes, in the end, a huge and unexpected increase in costs.

This paper refers to the drilling of an ultradeepwater wildcat exploration well located in the Turkish Black Sea, in water deeper than of 2000 m (6,560 ft), that reached a final depth greater than 5000 m (16,405 ft). This well was drilled by Petrobras using the fifth-generation semisubmersible Leiv Eiriksson drilling rig, operated by Ocean Rig.