bluuebunny/crossref_metadata_2025 huggingface dataset:
Sour Gas Interest Grows in Middle East
Authors: Henni Abdelghani
Published: February 2015

Middle East Sour Gas

Growing global demand for natural gas has pushed oil and gas companies to increase the development of sour gas fields, which contain about a third of the world’s gas reserves.

The defining chemicals in sour gas are often hydrogen sulfide (H2S) and car-bon dioxide (CO2), though in some cases, other sulfurous compounds such as carbonyl sulfide and mercaptans are also found. The higher concentrations in sour gas demand more intensive and more expensive development processes.

In the Middle East, developing sour gas fields have become a priority of local governments because of soaring regional gas consumption. In addition to tapping the development of new sour gas fields, companies in the region are also facing the issue of increasing level of sourness in operating fields in which the levels of H2S and other contaminants that were negligible on startup have become a problem later in production.

UAE: Moving Ahead

Fareed Abdullah, senior vice president (Bab and Gas) at Abu Dhabi Company for Onshore Oil Operations (ADCO), said the development of sour gas fields in the United Arab Emirates is a priori-ty given the growing gas requirements for power generation, gas injection to boost oil production, and the rising petrochemical sector.

“It is expected that the Shah field will produce first gas in the fourth quarter of 2014, and the importance of future sour fields such as Bab, Hail, and Shuwaihat plus others under evaluation is underlined by the current activity levels and consideration within the Abu Dhabi National Oil Company (ADNOC) Group,” he said recently at the Sour Oil and Gas Advanced Technology conference in Abu Dhabi.

“When the Shah field is operation-al in 2014, it is expected to increase gas capacity by 10.34 Bcm/yr, and all aspects of this project will serve as bench-marks for future sour gas development,” he said.

ADNOC selected Shell to participate in a 30-year joint venture to develop the Bab sour gas reservoirs in Abu Dhabi. Shell will hold a 40% equity stake with ADNOC holding 60%. The two companies are beginning commercial and technical work leading up to the development of Bab, which is 150 km southwest of Abu Dhabi. Gas from the field will supply local markets.

During the bidding process for the USD 10 billion deal, Shell recommended exporting the sulphur while another major bid recommended reinjecting it back into the reservoir. Once developed, the Bab field will produce 500 MMcf/D to 800 MMcf/D, but expertise is required to handle the large amounts of sulfur generated from the estimated 15% H2S content of the gas.

ADNOC has also sent letters to companies inviting them to submit bids for the offshore Hail sour gas field. With a CO2 content of 11%, Hail is less toxic than Shah or Bab. Because it is located in ecologically fragile shallow waters, ADNOC will proceed cautiously. Estimates suggest that Hail could produce up to 1 Bcf/D.
Q&A with Ali Rashid Al-Jarwan, CEO, Abu Dhabi Marine Operating Company
Authors: Al-Jarwan Ali Rashid
Published: February 2015

Q&A

What is the current production capacity of your company? What is your contribution to ADNOC’s overall production?

We are on the growth agenda, as is the case with all global oil and gas producing countries. As a subsidiary of Abu Dhabi National Oil Company (ADNOC), Abu Dhabi Marine Operating Company (ADMA-OPCO) is playing a major part in the ongoing efforts to increase oil production capacity by 35% to 3.5 million BOPD by 2018 from the current 2.7 million BOPD.

This production target is set to be achieved through three major subsidiaries of ADNOC: ADMA-OPCO, Abu Dhabi Company for Onshore Oil Operations (ADCO), and Zakum Development Company. For ADMA-OPCO, we are planning to increase production by 370,000 BOPD over current production levels of 550,000 to 600,000 BOPD. The new production target will be achieved mainly from the Lower Zakum field (100,000 BOPD) with 270,000 BOPD from the Umm Lulu, Satah Al-Razboot, and Nasr fields. 

Added to the Umm Shaif production share, which currently stands at 275,000 BOPD, and Zakum production of 325,000 BOPD, we are targeting a total production of 1 million BOPD by 2020.

Are the fields under development on track? What is the main scope of work at these fields?

Phase I of the Umm Lulu and Nasr fields is to assess reservoir behavior; however, we are already now moving to full field development of Umm Lulu. We awarded two pack-ages: The first package consists of seven towers and flowlines and a pipeline to Zirku Island to join SARB. For SARB, the company is moving to a full field development to produce 100,000 BOPD, and all seven engineering and construction packages have been awarded.

For the full development of SARB oil field, we have selected the construction of two artificial islands, SARB-1 and SARB-2, which are currently under construction by the ADNOC Civil Projects Division. The location of the islands is 120 km off the north-west coast of Abu Dhabi.

The onshore facilities engineering, procurement, and construction work under-taken by Hyundai covers processing, storage, and export facilities on Zirku Island and wellhead facilities on two artificial islands. Meanwhile, the offshore work undertaken by Petrofac mainly includes around 200 km of subsea pipelines, 55 km of subsea cables, a single point mooring crude loading facility, four offshore flares, and two riser platforms, in addition to drilling utilities on the artificial islands.

ADMA-OPCO has taken advantage of these major projects to develop and train young United Arab Emirates (UAE) nationals in engineering and project management.
Unplanned Downtime in the Gulf of Mexico: A Significant Production Loss Management Opportunity for Producers
Authors: Tucker Richard M. , Straub Tom , Feng Shu
Published: February 2015

Management

An analysis of 190 US Gulf of Mexico (GOM) producing assets in Ziff Energy’s field level operations database reveals significant opportunities for improving operating efficiency by reducing downtime. Total (planned and unplanned) production efficiency (PE) of these assets was found to be 88%.

Of the 12% production loss relative to potential (no downtime) production, 8% was a result of unplanned downtime, while 4% was either planned (i.e., accounted for in the company’s annual budgets) or a result of external causes, such as weather. This result indicates significant potential exists to increase production by reducing the frequency and duration of unplanned downtime (Fig. 1).

Economics of Improved Production Efficiency

The exploration and production (E&P) sector is historically a 10% to 15% rate of return business, which means that the last 10% to 15% of production is profit. If an operator could eliminate or reduce half of the 8% unplanned production loss, it could potentially double the rate of return from its assets. Because production loss management often can be done at small expense or investment, no other activity has the same potential to positively affect the bottom line. In short, production loss management is the best “margin lever” in the E&P business.

Based on 5-year (2008–2012) aver-age of GOM production of 1.39 million B/D of oil and 5,932 MMcf/D of gas, the additional annual production from recovery of all unplanned losses in the GOM could reach 102,000 B/D of oil and 582 MMcf/D of gas respectively (Fig. 2). The annual value of the recovered oil alone (without considering gas) would exceed USD 3 billion/yr. Deepwater rep-resents almost 80% of unplanned oil losses. Shelf gas, which accounts for more than half of total gas produced in the GOM, accounts for two-thirds of the unplanned gas losses.

Uptime Reliability Metrics

Ziff Energy has defined a family of metrics to assess uptime reliability. To determine production loss, an estimate of production capacity called predicted production capacity (PPC) can be used. Total production loss is the volumes of lost production due to all reasons. The total loss is derived by comparing actual annual production with PPC and consists of the following components:

Planned loss: Production loss because of scheduled downtime for repairs and maintenance or new well/facility tie-ins. An event is “planned” only when it is included in the annual budget. It should be noted that improvements in planned downtime are possible if the duration and frequency of planned events can be reduced resulting in improved production efficiency.

Unplanned loss: Production loss because of equipment/facility failures or operational upsets.

External loss: Production loss caused by external reasons, which are further broken down into midstream downtime, market limitations, and weather restrictions.
High-Reliability Gas Lift Flow-Control-Device Technology and Erosion/Endurance Tests
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159848, ’High-Reliability Gas Lift Flow-Control-Device Technology and Erosion/Endurance Tests,’ by Jun Xu, Stuart L. Scott, SPE, and Wayne Mabry, SPE, Shell E&P, and Jose Gamboa, SPE, The University of Tulsa, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.

High-reliability gas lift flow-control devices (GLFCDs) enable gas lift for wells with the potential for H2S in the produced gas and where casing is not qualified for H2S service. Valve specifications are such that no leakage is allowed at both high (8,000-psi) and low (1-psi) differential pressures across the valve. A series of tests was designed using the environmental-stress-screen (ESS) concept and a harsh test standard that greatly exceeds API specifications for GLFCDs.

Introduction

GLFCDs are usually incorporated into the production conduit and used to inject high-pressure natural gas from the injection conduit to the interior of the production conduit. Commercially available GLFCDs typically contain one-way check systems comprising a ball, hemisphere, or cone, which is pressed against a valve-seating ring by a spring. Unfortunately, many GLFCDs are prone to wear and damage because of fluid cut during the operation.

Some of Shell’s Gulf of Mexico deepwater wells commonly produce sour fluids, which the casing program was not designed to tolerate. When sour production enters casing that is not qualified to National Association of Corrosion Engineers standards, the wells cannot be produced. Therefore, a family of high-reliability GLFCDs has been developed for use in deepwater/subsea associations. This technology is viable for any gas lift well because of significant cost savings in change-out of GLFCDs and the ability to maintain well integrity. Fig. 1 presents schematics of the GLFCD through which liquids are unloaded from the casing annulus into the tubing, while Fig. 2 details several types of high-reliability GLFCDs.

High-Reliability-GLFCD Design Validation and Qualification Procedures

A series of design validation and qualification tests has been established and executed to determine whether high-reliability GLFCDs meet the acceptance criteria of API or ISO standards and Shell specifications and qualifications. Shell’s test program for these GLFCDs comprises three parts: factory acceptance, qualification, and endurance. Every individual GLFCD that has passed all factory-acceptance tests would be deemed accepted for installation and service. If the prototype of a GLFCD has passed Shell tests, it is deemed qualified to be a high-reliability GLFCD. Currently, three gas lift manufacturers have developed GLFCDs and products that have been tested using Shell’s test program; these test results are described in the following sections.
CO2-Sequestration Projects Adding Value
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 17089, ’The Plains CO2-Reduction Partnership: CO2-Sequestration Demonstration Projects Adding Value to the Oil and Gas Industry,’ by Charles D. Gorecki, Edward N. Steadman, John A. Harju, James A. Sorensen, John A. Hamling, SPE, Lisa S. Botnen, Scott C. Ayash, and Katherine K. Anagnost, Energy & Environmental Research Center, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

Carbon capture, use, and storage (CCUS) in geological media can be an important means for reducing anthropogenic greenhouse-gas emissions. Several geological settings are appropriate for geological storage of carbon dioxide (CO2), including depleted oil and gas reservoirs, deep brine-saturated formations, CO2-flood enhanced-oil-recovery (EOR) operations, and enhanced coalbed-methane recovery. The US Department of Energy is pursuing a program to demonstrate CCUS technology through its Regional Carbon Sequestration Partnership (RCSP) program.

Introduction

The Plains CO2 Reduction (PCOR) partnership, led by the Energy & Environmental Research Center, is one of seven regional partnerships established under the RCSP program. The PCOR partnership region includes all or part of nine US states and four Canadian provinces (Fig.  1) and is made up of many private- and public-sector groups working to identify the most-suitable CO2-storage strategies and technologies, aid regulatory development, educate the general public, and investigate appropriate infrastructure for CCUS commercialization within its region. The Phase-III program includes two commercial-scale projects—the Fort Nelson carbon- capture and -storage (CCS) feasibility project and the Bell Creek CO2-EOR/CO2-storage project.

Fort Nelson. The PCOR partnership and Spectra Energy Transmission are investigating CCUS to mitigate CO2 emissions produced by the Fort Nelson Gas Plant (FNGP) as a waste stream from natural-gas processing. FNGP is near the town of Fort Nelson in northeastern British Columbia, Canada (Fig. 2). The gas stream will include up to 5% hydrogen sulfide (H2S) and a small amount of methane (a sour-CO2 stream). The goal is to capture the stream of sour CO2 that is separated by the current gas-processing operations and store it long term in a deep saline formation. Currently, this sour CO2 is processed in an existing sulfur plant to recover elemental sulfur, and the residual CO2 and sulfur dioxide (SO2) are passed through an incinerator before venting to the atmosphere.
How Thirsty is Shale Gas?
Authors: Rao Vikram
Published: February 2015

Beyond the Headlines

Editor’s note: Professionals in the oil and gas industry often receive questions about how industry operations affect public health, the environment, and the communities in which they operate. Of particular concern today is the impact of hydraulic fracturing on the environment. In this new column, JPT is inviting energy experts to put those questions and concerns about industry operations into perspective. Additional information about the oil and gas industry, how it affects society, and how to explain industry operations and practices to the general public is available on SPE’s Energy4me website at www.energy4me. org.

The New York Times reported on 15 May 2014 that Butte County in California banned hydraulic fracturing because of concerns regarding freshwater consumption in a drought year. Shale oil and gas opponents have seized this issue even in parts of the country not suffering any significant drought. The perception of being deprived of drinking water has strong imagery. The facts beyond the headlines are decidedly not so dire.

A single shale oil or gas well will use between 3 and 5 million gal of water for drilling and completion operations. This sounds like a lot and, in some sense, it is a lot. But then you realize that the average golf course uses that much every 25 days, about the length of time it takes to drill a single well and start producing from it. It is also the amount of water that New York City uses every 4 minutes! Not a fair comparison, you say. Well, why don’t we compare it against other forms of energy?

Such comparisons are best made on the basis of liters of water per megawatt hour of energy. Shale gas production uses about 38 liters. In comparison, corn ethanol on average uses 32,000 to 370,000 liters (the higher end of the range is for irrigated corn), and the real shocker is soybean diesel, which comes in at 180,000 to 960,000 liters. In other words, corn ethanol uses more than 1,000 times more water per unit of energy compared with shale gas. Other sources suggest an even greater disparity in water usage (Science 2009).

Conventional fracturing fluid uses freshwater as the base fluid. Fresh is defined as 500 parts per million (ppm) or less of dissolved solids. The fluid returning to the surface after use, known as flowback water, is always saltier than what went in. Salinities of 200,000 ppm are not uncommon. As a frame of reference, seawater runs about 35,000 ppm. Recent advances in fracturing fluid chemistry allow for such flowback water to be reused without removing the salt down to fresh standards. Currently in the Marcellus shale play, some companies are reusing almost all of their flowback water with minimal treatment.
Unconventionals, Technical Challenges Highlight Offshore Technology Conference
Authors: Betz Jack , Carpenter Chris , Henni Abdelghani , Jacobs Trent , Parshall Joel , Rassenfoss Stephen , Wilson Adam
Published: February 2015

Conference Review - 2014 Offshore Technology Conference

The impact of onshore unconventionals development on the offshore sector, safety and environmental protection, and new opportunities and their technical challenges highlighted sessions and discussions during the annual Offshore Technology Conference (OTC), held 5–8 May in Houston. The broad program and exhibition, which attracted a record crowd, featured operators, independents, service companies, academia, and government officials weighing in on some of the most complex and pressing challenges facing the offshore industry.

The surge in North American shale development has brought major portfolio changes to E&P companies. This was the focus of one session in which six panelists discussed the impact of the unconventional “revolution” on the offshore deepwater industry.

Darrell Hollek, senior vice president for deepwater Americas operations and development at Anadarko, noted the huge change in his company’s production mix in the past 4 years. “If you go back (only) as far as 2010, we really had not drilled any horizontal wells,” he said. From that base of virtually no shale production, Anadarko has ramped up to production of 370,000 BOE/D from unconventional resources in 2014, and unconventional plays represent about 70% of the company’s capital budget, Hollek said.

Nonetheless, Anadarko’s mid-cycle and long-cycle projects—chiefly offshore activity, including deepwater projects— play a crucial role through generating high cash flow that has financed the company’s entry into onshore unconventional development, Hollek said.
Qatar Focuses on Building Energy R&D Capacity
Authors: Henni Abdelghani
Published: February 2015

Qatar R&D activities

Innovation and R&D have become top priorities for governments in the Middle East, mainly in the Gulf region. Qatar is striving to take the lead in this domain and has unveiled an ambitious plan to become the region’s energy R&D center now that it has completed a massive liquefied natural gas (LNG) production upgrade as part of its strategy to monetize its vast gas reserves.

Qatar’s plan to establish itself as a center of energy R&D is in line with its National Vision 2030, which aims to transform the nation from a hydrocarbon-based economy into a knowledge economy.

“R&D and technology have been at the heart of Qatar’s energy sector for many years, allowing it to unlock and commercialize the North Field’s vast gas reserves, and grow the country into the world’s largest LNG exporter,” said Hamad Rashid Al Mohannadi, chief executive officer of RasGas Company and chairman of the Board of Regents at Qatar University. He spoke recently at the Gulf Intelligence Qatar Energy R&D Forum in Doha in a presentation titled, “Qatar Energy R&D Next Steps - Moving from the Theoretical to the Specific.”

“Going forward, they will continue to play an important role in ensuring the sustainability of our industry, whose economic support underpins the ambitious Qatar National Vision 2030,” he said. “Qatar is blessed with a number of rooted establishments that enjoy strong financial backing to help set the direction for and facilitate these R&D and technology efforts. Our focus today should be on collaborating to effectively and efficiently address the grand challenges of energy, water, and cybersecurity.”

Faisal Alsuwaidi, president of research and development at the Qatar Foundation for Education, Science, and Community Development, said that Qatar energy officials have identified 72 objectives for a research agenda, “all of them with targets for sustainable development to improve the quality of life.”
Fracture Stimulation in the First Joint-Appraisal Shale-Gas Project in China
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16762, ’Successful Fracture Stimulation in the First Joint-Appraisal Shale-Gas Project in China,’ by Liang Jin, Changlong Zhu, Yong Ouyang, Ming Zhou, Qingguang Qu, Fei Li, Roger Yuan, Chris Wu, Zhiyi Zhang, Yan Wang, and Fa Dwan, Shell China Exploration & Production; Sanjay Vitthal, Shell Canada; and Shiqian Wang, PetroChina Southwest, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

This paper discusses fracture stimulation in the first joint-venture shale-gas project with foreign companies in China. The block is in Sichuan province, and the target zone is Longmaxi hot shale, a Silurian formation. Its matrix permeability is extremely low (100 to 300 nanodarcies), but it is rich in natural fractures. Hydraulic fracturing has been shown to be critical to enhancing production. A collaborative approach was applied to the completion of the shale gas wells during appraisal.

Introduction

Most of China’s proved shale-gas resources are in the Sichuan, Tarim, and Ordos basins. China’s technically recoverable shale-gas resources are estimated at 1,275 Tcf. The operator jointly appraised a shale-gas block in Sichuan with PetroChina. The project team needed to make several determinations in the early phase of the project, such as whether there is sufficient gas in the shale formation and whether the gas can be extracted at a high-enough (commercial) rate. From the production technologists’ perspective, the technical objectives of the early wells included the following:

Test the ability of the Longmaxi hot-shale interval to be fractured under high formation pressure.

Establish baseline fracture designs for the Longmaxi hotshale interval, at greater than 3500-m true vertical depth (TVD), and systematically evaluate the design parameters.

Establish an effective multidisciplinary workflow.

Gather fracture-stimulation-performance data and subsurface-pressure information.

Determine the productivity of the gas from the appraisal wells to prove the presence of a shale-gas play.

The joint-appraisal phase began in November 2010. While planning the drilling of deep wells to evaluate the Longmaxi formation, data were obtained from several shallow wells at a location close to the surface. Extensive laboratory tests were conducted to evaluate the geochemical properties of the rock. In addition, some rock-mechanics properties were measured. The drilling of the first well (Well A) began in December 2010, and hydraulic fracturing began once the well reached designed depth. To date, five wells have been drilled; two are vertical, and three are horizontal.
Unconventional-Reservoir Development in Mexico
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164545, ’Unconventional-Reservoir Development in Mexico: Lessons Learned From the First Exploratory Wells,’ by P.A. Parra, N. Rubio, C. Ramirez, B.D. Guerra, V.A. Exler, I.R. Campos, M.D. Trejo, J. Olguin, C.H. Vargas, R. Valbuena, D.F. Soler, M.I. Weimann, V. Lujan, and P. Bonningue, Schlumberger, and P.G. Reyes, R. Martinez, R. Munoz, E. Rodriguez, and M. Garcia, Pemex, prepared for the 2013 SPE Unconventional Resources Conference—USA, The Woodlands, Texas, USA, 10-12 April. The paper has not been peer reviewed.

In 2010, exploration of gas-rich and possibly liquid-rich shale reservoirs began in northern Mexico. A two-stage integrated workflow was developed to achieve set objectives. The drilling stage used a petrophysical and geomechanical static model to identify the most prospective interval in the reservoir, define the best drilling azimuth and landing point, and reduce drilling risk. Real-time geosteering was implemented to achieve the targeted navigation window. In the completion stage, reservoir-centric completion-and-stimulation software was used to optimize completion and stimulation design.

Introduction

The initial target formation was the Upper Cretaceous Eagle Ford; the second was a Jurassic formation locally called Pimienta.

The Eagle Ford shale is a Late Cretaceous hydrocarbon-producing formation composed of organic-rich calcareous mudstones with mineralogical composition with ranges of 5–20% quartz, 15–25% clay, and 65–80% carbonate, and with a total-organic-carbon (TOC) range of 1–6%. The Eagle Ford shale is overlain by the Austin chalk and overlies the Buda limestone. It has been divided into two units, a lower unit deposited during transgressive sequences and an upper unit deposited in a regressive sequence. Both units were deposited in a low-angle sloping ramp. As of July 2012, five wells had been drilled in the Eagle Ford formation: AEF, BEF, CEF, DEF, and EEF.

The origins of the Pimienta formation date to the Late Jurassic. It is an organic-rich source rock with potential for hydrocarbon production as an unconventional reservoir. Its mineralogical composition exhibits ranges of 20–40% quartz, 25–45% clay, and 20–40% carbonate, with an average TOC range of 3–4%. As of July 2012, one well (AP) had been drilled in the Pimienta formation.
Unconventional-Asset-Development Work Flow in the Eagle Ford Shale
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168973, ’Unconventional-Asset-Development Work Flow in the Eagle Ford Shale,’ by David Cook, Kirsty Downing, Sebastian Bayer, Hunter Watkins, Vanon Sun Chee Fore, Marcus Stansberry, Saurabh Saksena, and Doug Peck, BHP Billiton Petroleum, prepared for the 2014 SPE Unconventional Resources Conference - USA, The Woodlands, Texas, USA, 1-3 April. The paper has not been peer reviewed.

Development of the Eagle Ford shale typically consists of horizontal wells stimulated with multiple hydraulic-fracture stages. This paper presents a pragmatic integrated work flow used to optimize development and guide critical development decisions in the Black Hawk field. Geoscientists and reservoir and completion engineers worked collaboratively to identify optimal completion designs and well spacings for development focus areas. Multiple simplistic simulation models were history matched to existing production wells.

Introduction

In 2008, the operator drilled several successful wells in the Hawkville field of what would become the Eagle Ford shale play. Early results led to substantial land acquisition. The Eagle Ford, while continuous over wide sections, varies substantially in terms of fluid and rock properties. Fig. 1 shows a cross section for an arbitrary line through Black Hawk and Hawkville to the Maverick basin, showing the relative changes in thickness and Young’s modulus.

An understanding of the characterization of shale systems for simulation has evolved rapidly. Flow contributions from natural fractures, induced fractures, and matrix rock along with the nature of the hydrocarbon deposit itself should be considered. Perhaps even more important is regional variation. In the world of conventional assets, property estimation needs to be reliable only for a small geographical area, often within one sandstone structure of a few square miles at most. This can be compared with the scale of the play in Fig. 1. For conventional reservoirs, standardized laboratory methods and years of research and trial and error have educated our approaches to well-defined best practices. In shale plays, these have not yet been fully worked through and adopted by consensus, often leaving the owner of the asset as the arbiter of methodology.
Comments: Upstream Spending Optimism
Authors: Donnelly John
Published: February 2015

Editor's column

More than halfway through the year, signs point to a continued steady recovery in the upstream oil and gas sector. Several new surveys show that companies are increasing E&P spending this year, in spite of a shaky global economic situation and reduced drilling in the US Gulf of Mexico because of the Deepwater Horizon accident. 

This month’s Guest Editorial lays out the case for increased merger and acquisition (M&A) activity, based on economic optimism, which may continue for the rest of this year and into the next. The rise in shale gas appears to be the major source of momentum in M&A as large operators seek a stake in the game-changing unconventional play and oil reserves become more valuable in a potentially gas-saturated market.

Two major E&P spending surveys released recently forecast growth in E&P spending. The IHS Herold 2010 Global Upstream Capital Spending Report and Barclays Capital Original E&P Spending Survey both see significant rises in upstream capital spending this year. IHS Herold forecasts that E&P spending, excluding acquisitions, will increase 8% to USD 353 billion in 2010 compared to last year. The survey queried 110 of the largest publicly traded oil and gas companies.

This year’s rise compares to a 22% decline in upstream spending in 2009, when the global recession and tight credit markets forced companies to cut back. Smaller E&P companies in particular are benefiting from easier credit. The survey also confirmed that many companies are shifting their E&P focus away from gas to oil as oil prices continue to stay above USD 70/bbl. The survey predicts that because of the growing uncertainty over regulation caused by the Deepwater Horizon accident, some E&P spending will flow to onshore US activity or leave the US altogether.

Barclay’s spending report—a survey of 427 companies—forecasts that global E&P expenditure will rise 12% this year, with North American upstream spending rising faster than expected. US spending is increasing because of higher oil price expectations, the success of shale plays, and drilling to hold leases, but the threat of a deepwater drilling moratorium in the US Gulf of Mexico will lead to some spending reductions.

The report notes a decline in spending among Latin America companies. Venezuelan national oil company PDVSA has reduced its E&P spending by 25%, while spending by Mexico state energy firm Pemex has fallen 18% this year, according to the survey. Spending in Europe, the Middle East, and Africa is up slightly from a December 2009 survey forecast.

More than half of the companies surveyed expect upstream spending to continue to grow into next year. The survey says that 37% of the companies said they expect their spending will increase 20% or more, while 16% said they expected to increase spending by 10 to 20%.
Technology Focus: Formation Evaluation (August 2010)
Authors: Harrison Bob
Published: February 2015

Technology Focus

Analysts of conventional logs, who routinely evaluate complex formations, may be less productive when faced with more-esoteric responses from modern tools, especially because the latter often are interpreted by the logging contractors themselves. This situation arises because available petrophysical software may not be capable of handling the new log responses, and the required interpretive algorithms often are claimed as proprietary and, therefore, are withheld.

Logging-contractor-generated results from new logs may bring additional insight that is not readily apparent from basic logging suites, but end users must beware of blindly accepting these results and the implication that the new tools are necessary.

Many published case studies that claim new logging services are essential do not prove that basic logs are inadequate. Readers should be skeptical if these conference papers do not conform to Richard Feynman’s exhortation, “The idea is to try and give all the information to help others to judge the value of your contribution, not just the information that leads to judgment in one particular direction or another.” We should always ask ourselves three questions:

Was the log really necessary?

Does it add new information or simply confirm what could have been determined from a basic logging suite? For example, a nuclear-magnetic-resonance log in shaly gas-bearing sands with oil-based-mud-filtrate invasion may be able to distinguish gas from oil, but invaded-zone fluids also can be solved for by use of a combination of conventional logs.

Is the logging-contractor interpretation correct?

New logs should be validated against careful traditional-log analysis, which has been calibrated against core.

Can operators improve on the logging-contractor interpretation?

Yes! Operators have more relevant data and local knowledge, so they can use the log data more effectively. Petrophysical software and a log analyst’s time cost much less than log acquisition.

Logging contractors should run a safe and efficient operation while acquiring good raw data. If they also can supply an interpretation, then this is a bonus. End users must not abdicate their responsibility for the interpretation of log data that their employer pays to acquire.

Formation Evaluation additional reading available at OnePetro: www.onepetro.org

SPE 125342 • “Reservoir-Rock-Types Application—Kashagan” by A. Francesconi, Eni, et al.

SPE 128013 • “Residual Hydrocarbons—A Trap for the Unwary” by T. O’Sullivan, SPE, Cairn India, et al.

SPE 130414 • “Fulmar Sandstones—Correcting Some Received Wisdom in the Greater Kittiwake Area (North Sea)” by G. Coghlan, SPE, Centrica Energy, et al.
Fluid-Pressure Gradients in Tight Formations
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121982, ’Fluid- Pressure Gradients in Tight Formations,’ by J.A. Larsen, SPE, Statoil/ Consultant, and H. Urkedal and A. Lonoy, Statoil, prepared for the 2009 SPE Europec/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed.

Economical production from low-permeability reservoirs is a challenge. The oil/water contact (OWC) may not be at a precise level in the reservoir, and the vertical span of the oil/water transition zone may be large in such reservoirs. Traditionally, the free-water level (FWL) and, hence, the water and oil zones are determined from the oil- and water-pressure gradients. Pressure gradients are, however, difficult to obtain in low-permeability media, and supercharging effects may be the result of mobile oil and water being at the same place in the reservoir. 

Introduction

In the studied cases, vertical equilibrium between gravity and capillarity could imply that a large zone exists between oil and water that is frequently called the “oil/water transition zone” or “capillary-transition zone.” The fluid gradient derived from wireline-formation-tester (WFT) measurements showed a water gradient in the studied reservoir. The 130-m-thick vertical section was evaluated to have oil saturation generally higher than expected for residual-oil saturation, although the heterogeneous nature of the reservoir prohibited any direct conclusions. The main objective was, from a conceptual approach, either to verify a consistent relationship between water gradient and residual oil (paleozone) or, if no such conclusion could be made, try to quantify oil mobility. Only wells drilled with water-based mud were considered.

Initial Fluid Distribution in the Transition Zone. The capillary-transition zone can be defined as regions in the reservoir in which both oil and water are present, the water saturation is higher than the connate-water saturation, and the oil saturation is higher than the residual-oil saturation (i.e., both phases are mobile). Such regions need special attention for characterizing the initial conditions and for designing special-core-analysis programs for generating input data for dynamic simulations. The precision of production forecasting for primary-, secondary-, or tertiary-recovery methods relies on the proper description of the initial conditions in the reservoir.

Three types of initial fluid distributions can be defined and classified according to their distinct behavior. The main challenges are to select the correct oil/water capillary pressure function for deriving the water saturation and to find the correct position of the FWL. The OWC will, in most cases, be imprecise, and reference should always be made to the FWL, which may be above or below the OWC (deepest mobile oil).
Perdido Development: Subsea and Flowline Systems
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20882, ’Perdido Development: Subsea and Flowline Systems,’ by G.T. Ju, H.S. Littell, T.B. Cook, M. Dupre, K.M. Clausing, E. Shumilak, SPE, and W.W. Schoppa, Shell, and W.A. Blizzard, Seahorse Deepwater Technology, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

The Perdido development is in the western Gulf of Mexico in 7,817 ft of water. It is being developed with sub-sea technologies to mitigate key development challenges including extreme water depth, rugged seafloor terrain, low-pressure reservoirs, and aggressive hydrate-formation tendency. An overview of the subsea and flowline systems and the associated flow-assurance strategy is presented. The enabling technologies were a subsea-boosting system (SBS) and the surface blowout preventer (BOP) for drilling and completing subsea wells.    

Introduction

The Perdido development includes the Great White, Silvertip, and Tobago fields and is in the Perdido basin and fold belt in the Alaminos Canyon Protraction Area. This area is 200 miles south of Freeport, Texas, USA, and 8 miles north of the Mexico maritime border. All three fields are developed with subsea wells tied back to the host, which is a spar with full offshore-processing capabilities and pipelines for export.

Significant challenges include the  following.

Extreme water depth—7,800 to 9,600 ft, representing significant installation, operation, maintenance, and flow-assurance challenges.

Problematic seafloor terrain—rugged seafloor terrain in this area includes geologic features such as fluid expulsion, seafloor erosion, and steep slopes. These features make the subsea-equipment layout and choice of host location extremely challenging.
Subsea-Hardware Installation From an FDPSO
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20495, ’Subsea-Hardware Installation From an FDPSO,’ by Thomas J. Stensgaard, Murphy West Africa, and Charles E. White and Kevin R. Schiffer, Doris Inc., prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

Subsea installation for deepwater-field developments requires specialized vessels to carry out the work. A floating drilling, production, storage, and offloading (FDPSO) vessel positioned directly over the drill center provides an alternative to traditional methods. Unique challenges related to subsea-hardware installation from an FDPSO and the methods developed to overcome those challenges are presented.    

Introduction

The FDPSO is over the wells for direct access (Fig. 1). Therefore, performing subsea-construction and -intervention activities directly from the host becomes possible. The FDPSO provides a large stable platform from which these activities can be accomplished, but it has limited access and maneuverability, and challenges that must be addressed. These challenges were overcome in the Azurite field in the Mer Profonde Sud Block offshore the Republic of Congo. The FDPSO was fitted with a remotely-operated-vehicle (ROV) spread and a crane sized to install heavy hardware.

Subsea Scope and Field Architecture

The Azurite field subsea architecture was driven primarily by the excursion capability of the FDPSO, which was in turn determined by the mooring system, flexible-production-riser limitations, and water depth. All production and injection wells were required to be within a 45-m radius, enabling access by the drilling rig on the FDPSO. This close well spacing supported either a template development or a tight cluster of wells in a radial array around a subsea manifold. The cluster configuration was chosen, with wells surrounding a combined production/water-injection manifold as shown in Fig. 2. The multiphase pumps and a subsea distribution unit (SDU) were placed nearby but outside of the drilling circle to permit intervention activities from the FDPSO if problems arose.

FDPSO vs. Subsea-Construction Vessel

Several functional requirements must be provided for nearly all subsea-installation campaigns and include the following.

Transportation of equipment to the offshore worksite

Lifting capacity offshore

Means to lower equipment to and land equipment on the seafloor

Underwater control and intervention

Subsea-positioning capability

Typically, a subsea-construction vessel equipped for these functions is used. However, these vessels are expensive and have limited windows of availability. With the FDPSO, with the host directly over the drill center, an alternative to traditional subsea installation was studied. The FDPSO provides an inherently stable work platform from which to perform installation operations.
En Route: Increasing Recovery Factors: A Necessity
Authors: Labastie Alain
Published: February 2015

President's column

To satisfy the increasing energy needs of the world during the next decades, adding substantial new oil reserves will not be an option, but a necessity. There are different ways to achieve that:

Continuation of exploration. Exploration for new resources will continue to play an important role but will become more difficult and will not be sufficient to meet our needs.

Development of unconventional oil, like oil sands and oil shales. Unconventionals are quite promising, but production will increase slowly.

Improvement of the recovery efficiency of our producing fields. This means producing a fraction of the enormous amount of oil that is currently being left underground.

The current ultimate average recovery factor for oil fields, on a worldwide basis, is about 35%. This means that about two-thirds of the oil that has been discovered is left within the reservoir. We have under our feet, in well known locations, enormous prospects for booking new reserves. Increasing the average ultimate recovery factor from 35% to 45% would bring about 1 trillion bbl oil! The questions are how to achieve that goal, and is it realistic?

How? Technology will be the key, in many domains: advanced wells with more contact with the reservoir, more efficient lifting systems, devices such as downhole or seafloor separation, better reservoir monitoring and management, and, very importantly, tertiary recovery or enhanced oil recovery (EOR).

Is it possible? We know the answer, it’s “yes.” Why? Because this has been done in one place already, Norway. In this country, a continuous policy of incentives for developing and, more importantly, deploying new technology has been in place for the last 30 years. And the overall results are quite impressive. Thanks to many new technologies the average ultimate recovery factor has been increased by more than 10% during this period.

I would like to elaborate a little on EOR, as it will certainly play an important role. EOR was promising 30 years ago, but it never developed as well as many people anticipated. However, it is interesting to note that although EOR production is relatively small today, it is still significant—around 3 million B/D. I recently visited the giant Daqing oil field in China. This field is now very mature, with a water cut of more than 90%, but the oil production rate has maintained constant over years thanks to a progressive deployment of polymer flooding, which is now implemented in about one-third of the field. That is an impressive success story and an example for rejuvenation of mature fields. Also, a number of EOR projects have been launched recently. This includes small-scale pilots, but also a lot of large-scale operations.
Whole Core vs. Plugs: Integrating Log and Core Data to Decrease Uncertainty in Petrophysical Interpretation and Oil-In-Place Calculations
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137679, “Whole Core vs. Plugs: Integrating Log and Core Data To Decrease Uncertainty in Petrophysical Interpretation and STOIP Calculations,” by S. Serag El Din, SPE, ADCO; M.R. Dernaika, SPE, Weatherford Laboratories; I. Al Hosani, ADCO; L. Hannon, Weatherford Laboratories; S.M. Skjeveland, SPE, University of Stavanger; and M.Z. Kalam, ADCO, prepared for the 2010 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, 1–4 November. The paper has not been peer reviewed.

Most carbonate reservoirs are characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross reservoir interval. The specific types and relative percentages of pores present, and their distribution within the rocks, exert strong control on production and stimulation characteristics of carbonate reservoirs. The effects of heterogeneity on core and log measurements are presented. The challenge is to determine the reliability of applying relatively small-scale properties measured by a log or core to the large-scale reservoir property.   

Introduction

Most sandstone reservoirs are single-porosity systems (i.e., interparticle pores) of relatively uniform (homogeneous) nature. However, most carbonate reservoirs are characterized by multiple-porosity systems. Reservoir heterogeneity results from physical and chemical reorganization processes over time (e.g., compaction, solution, dolomitization, and cementation). Heterogeneity complicates the reservoir-description task, in which reservoir properties (e.g., permeability, porosity, saturation, and rock types) tend to vary as a function of spatial locations in vertical and areal directions. Vertical heterogeneity has shown large effects on sweep efficiencies of waterfloods and conventional gas injection into mixed- to oil-wet carbonate reservoirs. These effects are a result of large variations in permeability between different strata. Permeability and other rock properties can vary along the areal (lateral) direction of the reservoir, which necessitates establishing an accurate and detailed understanding of geological heterogeneities and their effect on petrophysics and reservoir engineering.

The effect of rock heterogeneity becomes greater when petrophysical properties are measured at scales ranging from a small trim sample in the laboratory to log measurements in the field. Permeability variation of three orders of magnitude has been reported over a distance of a few centimeters in a carbonate-core plug. In heterogeneous reservoirs, the real challenge is predicting reservoir performance through the acquisition of representative measurements. The challenge would be to reconcile the variability seen in high-resolution (e.g., trim or plug samples) and low-resolution (e.g., wireline logs) measurements and to quantify the technical and physical considerations at the various scales.