bluuebunny/crossref_metadata_2025 huggingface dataset:
Benchmarking Industry Talent Needs
Authors: Soupa Oliver
Published: February 2015

Talent & Technology

Since 2004, Schlumberger Business Consulting (SBC) has produced the SBC Human Resources (HR) Benchmark to assess the global supply and demand for petrotechnical professionals (PTPs; covering geosciences and petroleum engineering disciplines) and highlight best practices in talent management. This annual survey has become the reference point for industry professionals who seek talent strategies that have a measurable impact on business results. The survey has found its place within the SPE Talent Council,* whose members, some of whom participate in the survey, use the results as a basis for discussion to identify potential areas of industry collaboration to improve the quantity and quality of talent available.

The SBC copyrighted The Supply Chain of Talent (Fig. 1) is the cornerstone of the SBC HR Benchmark. This framework was established by SBC to provide a holistic and systemic way to understand and address overall HR challenges in the industry. Many SBC clients today adopt The Supply Chain of Talent in their HR planning and management processes to address difficult HR issues that have proven complicated in the past. Addressing all these HR components in an integrated way has resulted in a higher impact than a piecemeal approach.

The 2009 Benchmark results were presented during the annual SBC HR Forum in December.  More than 20 global companies comprising national oil companies (NOCs), majors, independents, and 70 universities, which offer geosciences and petroleum engineering programs, participated in the survey. Three major observations were made based on the survey findings:

In the recent economic downturn, international oil companies (IOCs) decreased their recruitment targets more than NOCs, putting university oil- and gas-related programs at risk and possibly creating future talent gaps.

Oil and gas companies have taken steps to adjust their demographic profiles.

Coaching is a valuable tool to reduce the time to autonomy for PTPs.

*The SPE Talent Council was formed in 2007 to provide a forum in which industry, academia, and nongovernmental organizations could collaborate on initiatives to increase the quantity and quality of talent available to the industry.
Dynamic Updating of Reservoir Models
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123671, ’Dynamic Updating of Reservoir Models,’ by Harun Ates and Asnul Bahar, SPE, Kelkar and Associates, and Vitaly Krasnov, SPE, Rosneft, and Mohan Kelkar, SPE, University of Tulsa, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

In sandstone reservoirs, an important challenge is scaling up a fine-scale model effectively. Conventional methods are not adequate when significant shale distribution exists in the reservoir. In the fine-scale model, some sand bodies are connected to the wells and some are not. As the fine-scale model is scaled up, some discontinuous sand bodies become combined with connected sands. A new procedure was developed to overcome this problem.   

Introduction

Traditional reservoir modeling involves developing a fine-scale geocellular model that incorporates the small-scale static uncertainties. Once such a description is created, it is scaled up to an appropriate scale such that it can be flow simulated to understand the dynamic performance of the reservoir. It is difficult to flow simulate a fine-scale model because it is computationally demanding.

Some sandstone reservoirs tend to be highly discontinuous, with sand and shale dispersed within the reservoir. The continuity of the sand bodies may not be known precisely and reflects an uncertainty in static models. The problem becomes even more complex if the reservoir is thick and contains multiple thin sand bodies. When a fine-scale model is constructed, it may contain many vertical layers to account for all the thin sands present in the reservoir.

Scaling up of such models is very difficult because of the following.

If the model is coarsened (scaled up) significantly, many of the discontinuous sands will connect to other sands, and this will increase the pore volume (PV) “connected” to the wellbore, changing the transmissibility (connectivity) distribution between wells.

In the scaled-up model, because of artificially connected sands, infill wells would not indicate true potential of additional recovery because some of the virgin sands that would have been connected to the newly drilled wells would show to have been drained already by existing wells in the model.

If the model is maintained at relatively fine scale, the simulation can be computationally demanding. The dynamic modeling (e.g., history matching) would be more time consuming. Therefore, many uncertainties may not be investigated correctly.
Modeling Well Performance in Shale-Gas Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125532, ’Modeling Well Performance in Shale-Gas Reservoirs,’ by C.L. Cipolla, SPE, Carbo; E.P. Lolon, SPE, StrataGen Engineering; and J.C. Erdle, SPE, and V. Tathed, SPE, CMG, prepared for the 2009 SPE/EAGE Reservoir Characterization and Simulation Conference, Abu Dhabi, UAE, 19-21 October 2009. The paper has not been peer reviewed.

This paper focuses on modeling well performance in shale-gas reservoirs by use of numerical simulation. Stimulation treatments in many shale-gas reservoirs create very complex fracture networks. These fracture networks are required to achieve economic production rates from rock with a matrix permeability as low as 10 nanodarcies. The primary issues with modeling production from shale-gas reservoirs are describing gas flow from the tight shale matrix into the fracture network accurately, properly characterizing the matrix-block size (or fracture density) and the conductivity of the network fractures, and evaluating effects of stress-sensitive network-fracture conductivity and gas desorption.   

Introduction

Gas shales are organic-rich formations that are both source rock and reservoir. Gas is stored in the limited pore space of these rocks, with a sizable fraction of the gas in place possibly adsorbed on the organic material. Typical shale-gas reservoirs exhibit a net thickness of 50 to 600 ft, have porosity of 2 to 8% and total organic carbon of 1 to 14%, and are found at depths of 1,000 to 13,000 ft. The success of the Barnett shale in the USA has illustrated that gas can be produced economically from rock that was previously thought to be source rock and/or caprock, not reservoir rock, leading to the development of many other shale-gas reservoirs, including the Woodford, Fayetteville, Marcellus, and Haynesville.

The economic viability of many unconventional gas developments requires effective stimulation of extremely low-permeability rock, typically 0.0001 to 0.00001 md. In most cases, economic production is possible only if a very complex, highly nonlinear fracture network can be created that effectively connects a large reservoir surface area to the wellbore. Many conventional hydraulic-fracture treatments use high-viscosity fluids to reduce fracture complexity and promote planar fractures, allowing the placement of high concentrations of large proppant. However, stimulation treatments in shale reservoirs use large volumes of low-viscosity fluid (water) to promote fracture complexity and place very low concentrations of small proppant. Hydraulic-fracture treatments in horizontal wells can require several million gallons of water and up to 1 million lbm of proppant pumped at rates of 75 to 150 bbl/min.
From Flowback to Fracturing: Water Recycling Grows in the Marcellus Shale
Authors: Rassenfoss Stephen
Published: February 2015

In Pennsylvania, recycling water from wells in the Marcellus Shale has been transformed from a trend to an essential skill. The tipping point came in mid-April in a notice from the state’s Department of Environmental Protection (DEP) telling 15 public water treatment plants to stop handling waste water from wells in the Marcellus.

The order to the only public facilities treating water from fracturing was voluntary, but the intent was clear. In the letter, Michael Krancer, the DEP secretary said: “Now is the time to take action to end this practice.”

If there was any doubt, the US Environmental Protection Agency (EPA) followed up with a letter in May telling the state agency to make that a mandatory order. The federal agency said it would contact large oil and gas companies and the water treatment facilities to ensure they were no longer processing water that had flowed back after fracturing, and then disposing it in the state’s waterways.

At that time two-thirds of the water from fracturing was recycled in Pennsylvania, where water use for shale gas companies has become a battleground with environmentalists, politicians, and the people who live on the land holding enormous natural gas reserves. The industry was already moving toward recycling, said Pete Miller, water resources manager of the Marcellus Shale division at Range Resources, which reuses nearly all the water from its wells there. “When the standard came out, it was another push in that direction.”

The state’s letter sparked a rush by those who faced higher disposal costs because they could no longer have their waste water treated in state. “People are calling and telling me, ‘I’ve got to figure this out,’” said Dave Grottenthaler, general manager of Kroff Oil Services, a Pittsburgh water treatment specialist that got into fracturing water reuse early on. “I’ve been telling them for a while, you can reuse all your flowback and you will be safe.”

Range Resources is evidence to how fast this transition can happen. It first used a mixture of fracturing flowback water and fresh water in August 2009. In 2010, it said it reused 96% of its produced water in Pennsylvania.
Technology Focus: Reservoir Simulation (July 2011)
Authors: Crick Martin
Published: February 2015

Technology Focus

Simulation is about building a mathematical model of the reservoir and then using it to predict, for the purpose of making decisions. That may be restating the obvious, but there are a few points that bear a little re-emphasis. First, it is only a model. Second, if the model does not predict adequately, it does not serve its purpose. There is a growing tendency in some quarters to use very simple models—mainly because they are faster. As my colleague Ed May recently put it, “I know everyone pushes for faster, faster, but doing it right has definite advantages.”

Following my recent move into well testing, I have been rereading the late Laurie Dake’s The Practice of Reservoir Engineering. Dake often is regarded as hostile to simulation, but what he really was about was understanding your assumptions, and using the most appropriate model for the decision to be made.

At the 2011 SPE Reservoir Simulation Symposium, many papers focused on re-examining original basic assumptions. Correcting or removing those assumptions (improving the model) often led not only to better predictions, but to faster simulation. For example: Is the most recent solution of the well model the best starting point for the next solution? As the industry develops more-complex reservoirs (e.g., shales, naturally fractured, and heavy oil), we are called on to apply our simulation tools to new environments, and we must check constantly that the assumptions that are implicit in those tools are still valid. For example: Do assumptions for light-oil flow in homogeneous sandstone also apply to gas flow in shale?

The need to check assumptions applies as much to the data as to the tools. In simulation support, we often see data sets in which hundreds of warning messages about bad data are ignored or even suppressed, and the complaint is about the final failure to converge. Is that discontinuity in the pressure/volume/temperature data really a property of the fluid, or just a measurement artifact?

A good way to consistently challenge your assumptions is to read the best of the best technical articles: JPT is here for you!

Reservoir Simulation additional reading available at OnePetro: www.onepetro.org

SPE 144401 • “Design and Examination of Requirements for a Rigorous Shale-Gas-Reservoir Simulator Compared to Current Shale-Gas Simulators” by Juan Andrade, SPE, University of Oklahoma, et al.

SPE 140882 • “Multilateral Complex-Well Optimization” by P.I. Crumpton, Schlumberger, et al.

SPE 137507 • “Reservoir Characterization and Flow Simulation of a Low-Permeability Gas Reservoir: An Integrated Approach for Modeling Tommy Lakes Gas Field” by H. Deng, University of Calgary, et al. (See Journal of Canadian Petroleum Technology, May 2011, page 32.)

SPE 141935 • “An Adaptive Newton’s Method for Reservoir Simulation” by Pengbo Lu, ExxonMobil, et al.

SPE 142093 • “A New Method To Model Relative Permeability in Compositional Simulators To Avoid Discontinuous Changes Caused by Phase-Identification Problems” by Chengwu Yuan, SPE, University of Texas at Austin, et al.
Modeling, Simulation, and Optimal Control of Oil Production Under Gas-Coning Conditions
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 143520, ’Modeling, Simulation, and Optimal Control of Oil Production Under Gas-Coning Conditions,’ by Agus Hasan, SPE, and Bjarne Foss, SPE, NTNU; and Svein Ivar Sagatun, Bjorn Peter Tjostheim, Atle Svandal, and Cato Hatland, Statoil ASA, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed.

Gas coning is the tendency of gas to impel oil downward in an inverse-cone contour toward the well perforations. After gas reaches the well, gas production will dominate the flow stream and oil production will decrease significantly. In this paper, the gas-coning process in a gas/oil reservoir (completed with a single horizontal well) is modeled, simulated, and analyzed by applying a nonlinear-control approach. The model that describes the well/reservoir interaction can be a boundary-control problem of the porous media with two boundary conditions: a Neumann boundary condition describing no flow at the outer boundary of the reservoir and a nonlinear-boundary condition describing the well’s production rate.   

Introduction

Optimizing the trade-off between oil and gas production is important in reservoir management. The use of secondary-recovery techniques (e.g., gas lift and waterflood) and enhanced-oil-recovery techniques (e.g., surfactant injection) has proved successful for increasing oil production significantly. These techniques are supported by the use of smart-well technologies. A smart well is one that is equipped with several valves that can be regulated during production. Operating these valves can be accomplished by use of optimal-control theory, particularly when combined with the adjoint method. Adjoint-based optimization can be used to determine optimal well placement and for history matching. Optimal-control theory combined with data assimilation forms a closed-loop reservoir management.

Although providing solutions in a relatively short time and in an efficient way, the adjoint method is difficult to implement because one needs access to the reservoir-simulator code to implement the algorithm. An alternative is creating a mathematical model that is simpler but can be used to explain the same physical process. This model is referred to as a proxy model and serves as a representative of a complex model that usually is contained in a reservoir simulator. A proxy model may be derived from a basic principle of physics, such as mass conservation or Darcy’s law. The proxy model is simpler and easier to work with than the high-fidelity model.
Technology Focus: Overview: Artificial Lift (July 2011)
Authors: Noonan Shauna
Published: February 2015

Technology Focus

The electrical-submersible-pump (ESP) industry has achieved many milestones this year, with a new publication, record-setting workshop, and an international standard in development.

Recently, SPE published its first reprint on ESP technology. This volume contains key papers that give a “state of the industry” perspective on the extent to which ESP technology has evolved and which areas have been most pre-dominant. Topics include subsea and deepwater applications, extreme environments, alternative deployment, reliability information, and failure tracking. It is available online as a digital edition from the SPE Bookstore. (Lesson learned—First, check with your information-technology department to ensure that your company supports use of the digital-editions software.)

In April 2011, the SPE ESP Workshop (sponsored by the Gulf Coast Section) had a record attendance of 560 people from 24 countries. This 5-day event included continuing-education classes, a technical session with 31 papers, and a sold-out exhibition area. To learn more about this event, go to www.espworkshop.com.

It was at the SPE ESP Workshop that the industry caught its first glimpse of what is being covered in the new international standard for ESPs (ISO 15551-1). The ISO ESP committee has been working hard over the past 11/2 years to draft a standard that contains requirements for pumps, gas handlers, intakes, mechanical gas separators, cables and motor-lead extensions, seal-chamber sections, and induction motors. The expected date for publishing ISO 15551-1 is 2013, the same year as the next SPE ESP Workshop.

Papers selected for this feature cover three areas of ESP research and advancement: understanding how liquid viscosity under two-phase-flow conditions affects centrifugal-pump performance, pushing ESP technology for deepwater developments, and a case study on reliability improvements through data col-lection, interpretation, and benchmarking.

Artificial Lift additional reading available at OnePetro: www.onepetro.org

SPE 134068 - “Application of Composite Jet-Rod Pumping System in a Deep Heavy-Oil Field in Tarim, China” by Jianxin Shen, China University of Petroleum, Beijing, et al.

SPE 142764 - “Assessing Gas Lift Capability To Support Asset Design” by James W. Hall, SPE, Qatar Petroleum, et al.

SPE 137264 - “Inherent Dangers in PCP Run-Life Field-Data Analysis” by John Sheldon, SPE, C-FER Technologies, et al.
Technology Focus: Unconventional Resources (July 2011)
Authors: Polikar Marcel
Published: February 2015

Technology Focus

The future of “unconventionals” is upon us! The 21st century will see the growth of clean renewable-energy sources. Natural gas will play a prominent role. Currently, a large portion of the natural gas comes from unconventional sources (e.g., shale gas, tight gas, coalbed methane, and, soon, gas hydrates). Shale and tight gas exploitation are widely commercialized, with constant improvement of fracturing techniques to increase yield and decrease costs. North America is leading the way in unconventional-resources recovery and technology development. Transfer of these technologies to up-and-coming players has become essential. This has to be managed carefully to minimize environmental, societal, and political effects.

Nations that are deficient in natural resources are turning to importing necessary fuels or wisely gathering renewable resources. For example: What will Japan do after the accident at the Fukushima nuclear plant? Will it still invest as much as it used to in nuclear power to supply its energy needs? Will Japan increase its imports of nonrenewable energies, such as liquefied natural gas, or rely on renewable energies such as wind power? What will be the nature of its main demand for energy in the near future and in the long term, and how will it strike a delicate balance between these options?

China has emerged as the second world power behind the USA. It also has immense nonrenewable resources that are being exploited. East/West relationships are changing with regard to energy resources. Other players besides China (i.e., India, Australia, and Europe) are starting to exploit their unconventional resources by taking advantage of the dissemination of new technologies. Inevitably, cards must be redealt in light of this new reality.

What are the new challenges of this century? Who will be the new energy partners of the western world, and what kind of relationships will be built? How will this new reality influence the choices of economic and resource development? Future opportunities are great, and unconventional resources clearly will play a key role in our future energy landscape.

Unconventional Resources additional reading available at OnePetro: www.onepetro.org

SPE 137667 • “Natural-Gas Hydrates: Development and Test of Innovative Methods for Gas Production From Hydrate-Bearing Sediments” by J.M. Schicks, Helmholtz Centre, Potsdam German Research Centre for Geosciences, et al.

SPE 140864 • “Managing Environmental Risks From Shale-Gas Exploration—Applying Lessons Learned in the US to New Ventures in Poland” by F.V. Jones, SPE, ERM Southwest, et al.

SPE 139723 • “Enhanced Gas Recovery and CO2 Storage in Coalbed-Methane Reservoirs: Optimized Injected-Gas Composition for Mature Basins of Various Coal Rank” by Karine Schepers, SPE, Advanced Resources International, et al.

SPE 144093 • “Application of Propane (LPG)-Based Hydraulic Fracturing in the McCully Gas Field, New Brunswick, Canada” by Don LeBlanc, SPE, Eastex Petroleum Consultants, et al.
CO2 Storage Capacity - Combining Geology, Engineering, and Economics
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 133804, ’CO2 Storage Capacity - Combining Geology, En gineering, and Economics,’ by W.G. Allinson, SPE, Y. Cinar, SPE, P.R. Neal, SPE, J. Kaldi, SPE, and L. Paterson, SPE, Cooperative Research Centre for Greenhouse Gas Technologies, prepared for the 2010 SPE Asia Pacific Oil & Gas Conference and Exhibition, Brisbane, Australia, 18-20 October. The paper has not been peer reviewed.

The authors contend that any capacity-estimation method requires a combination of geological, engineering, and economic analysis to provide rigorous capacity estimates. Also, the classification of capacity estimates should follow concepts in the existing SPE Petroleum Resources Management System (PRMS) as closely as possible. Definitions of petroleum resources can be applied to storage capacity, and a storage-capacity classification system is recommended. 

Introduction

As technology for carbon capture and storage (CCS) moves from research to deployment, there is a need to estimate the amount of carbon dioxide (CO2) that can be stored safely and securely in the subsurface. Much of the literature on estimating the capacity of geological sites for storing CO2 focuses on determining the total pore volume of a formation and then applying a “storage-efficiency factor” to quantify the portion of this resource that could be accessed for storage. Theoretical and practical pitfalls of such storage-capacity-estimation methods are identified. A more-appropriate means of estimating CO2-storage capacity uses a combination of geological, reservoir-engineering, and economic analyses. Such an approach leads directly to definitions of capacity that have direct correlation with SPE definitions of reserves and resources. Unless otherwise stated, the term “storage capacity” is used loosely here to mean that part of the Earth’s crust in which CO2 can be stored either practically or economically.

Estimating Storage Capacity

A difficulty in determining storage capacity by traditional methods and by use of reservoir simulation and economics is defining the area and thickness of the potential storage formation. Possibly straightforward for a structural trap having a single high-permeability sandstone layer bounded by sealing shale layers, these definitions become more difficult for interbedded sands and shales of varying quality, which leads to definitions that involve permeability- or porosity-cutoff values (usually defined without reference to commercial factors). In some cases, the thickness can be determined from techniques such as reflection seismology and geophysical well logging with some satisfactory accuracy. However, estimating the area can be particularly challenging.
On the Precipice of a New Energy Source?
Authors: Jacobs Steve , Leach Patrick , Nagel David J.
Published: February 2015

Guest editorial

In the late 1850s, the whaling industry was in a veritable boom in the town of Lahaina on the Hawaiian island of Maui. Business was great, and many in the whaling industry believed that increased demand would continue for decades to come. But in 1859, oil was discovered in Titusville, Pennsylvania with a well drilled by Edwin Drake. The rest is history.

That was 150 years ago. A small but increasing number of people around the world believe we are on a similar course, except this time it is the petroleum industry that might be threatened. As with any emerging technology, critical challenges must be overcome and a significant effort lies ahead to convince a world of skeptics that a new source of energy has been discovered and will be important.

The potential new source of energy is low-energy nuclear reactions (LENR). With any discussion of a new technology, caution is advised. The world of LENR is filled with mystery, contradiction, gross speculation, misinformation, slippery timelines, and skepticism that sometimes spill over into outright denial. Healthy skepticism on LENR (or any new technology) is a good thing, but so is an open mind. If LENR is for real—and many well-qualified physicists believe it is—it will not only change the petroleum industry, but also significantly affect almost every aspect of our world. Some call it “the new fire.”

In 1989 at the University of Utah, Stanley Pons and Martin Fleischmann announced they had discovered a cold fusion process that would ultimately result in cheap, limitless energy. The outcome from these cold fusion efforts became widely known and well documented, primarily because other researchers were unable to replicate the results from the initial experiments. Cold fusion was (and is) viewed as impossible by many in the scientific community. Although the research did not cease, it was largely ignored. For the past 20-plus years, a small number of scientists have been diligently working on what could eventually become a hugely disruptive technology.

According to New Energy Times, “LENRs are weak interactions and neutron-capture processes that occur in nanometer-to-micron-scale regions on surfaces in condensed matter at room temperature. Although nuclear, LENRs are not based on fission or any kind of fusion, both of which primarily involve the strong interaction. LENRs produce energetic nuclear reactions and elemental transmutations, but do so without strong prompt radiation or long-lived radioactive waste.” (“Strong interaction” and “weak interaction” refer to the strong nuclear force and the weak nuclear force, which—along with electromagnetic force and gravity—make up the four basic forces in nature.)
Pilot Test Shows Promising Technology for Gas Drilling
Authors: Li Jun , Liu Gonghui , Guo Boyun
Published: February 2015

Young Technology Showcase

Gas drilling has been widely promoted and applied in China in recent years. The cuttings-carrying media usually consist of air, nitrogen, and natural gas. Air is commonly used because of its free availability. However, the mixture of air and natural gas in a borehole can cause fire and explosion. Although the downhole fire problem is prevented with nitrogen or natural gas, other issues arise, such as costly nitrogen generation, restrictions to the use of natural gas, resource waste, and environmental concerns.

The current gas drilling practice of handling gas returned from the borehole is to discharge it to the atmosphere directly. If the gas can be recycled in the same way as drilling mud, the energy consumption and drilling cost can be greatly reduced. The recycling system can also allow the produced gas from the reservoir to be compressed and transported to the gas gathering system in the field. The overall efficiency of gas drilling will be improved significantly.

The gas recycling system (GRS) has been investigated at the China University of Petroleum, Beijing (CUPB), for several years. A systematic research and development group at the CUPB carried out a comprehensive study including an integration design, technological process investigation, cuttings transport analysis, separation and filter equipment selection, and control system design. To verify the feasibility of the new system and technology, CUPB recently conducted an open-loop field test at Sinopec Group’s Dayi 101 well in the Sichuan province in western China. The result of the test is very promising. It proved the feasibility of the innovative technology.

System Description

The general idea of the GRS is to separate gas effectively from the gas-liquid-solid mixtures returned from the well and reinject the gas back into the well. At the same time, cuttings and fluids are discharged after the separation. During the natural gas drilling process, the separated gas can be released to the gas gathering system in the field. The integrated design of the process is illustrated in Fig. 1.
Pressure Distribution in Progressing-Cavity Pumps: Performance and Run Life
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 153944, ’Pressure Distribution in Progressing-Cavity Pumps: Test Results and Implications for Performance and Run Life,’ by Evan Noble, SPE and Lonnie Dunn, SPE, Weatherford, prepared for SPE's Progressing Cavity Pumps 2011 Digital Edition. The full manuscript is available as a supplement to this article.

Conventional thought has assumed that pressure builds linearly along the length of progressing-cavity pumps (PCPs). Rotor sizing and pump-lift selection have been based on this assumption. A series of laboratory tests investigated the buildup of pressure and temperature along the length of a PCP. The test results help explain common field-failure modes and can be used as a basis for selecting pump assemblies for challenging applications.

Introduction

Since being introduced to the oil field several decades ago, PCPs have been assigned a pump-pressure rating. This rating is the theoretical pressure difference at which a given PCP model can operate while maintaining acceptable performance and life. The pump-pressure rating, also called lift, generally is listed in terms of differential pressure across the entire pump and in terms of meters or feet of fluid head, psi, or kPa. Generally, a pump is selected with a higher pump-pressure rating than is required for the application, to provide a safety factor. The pump-pressure rating is based on the number of pitches in the pump and the cavity-pressure rating. The cavity-pressure rating is the theoretical pressure difference at which a sealed cavity is recommended to operate to ensure acceptable performance and life. The cavity-pressure rating is the difference between the pressure in a sealed upstream cavity and the pressure in the sealed cavity immediately downstream in the pump. The cavity-pressure rating is a manufacturer-established value and can range from 50 psi/pitch to more than 140 psi/pitch. Cavity-pressure ratings can vary with pump geometry, elastomer strength and design, and manufacturer preference. Cavity-pressure ratings assume that pressure builds inside the pump in a linear fashion, and the cavity-pressure rating is the rate of constant pressure buildup. To determine the pump-pressure rating, the cavity-pressure rating is multiplied by the number of pitches. To create a pump with a higher pump-pressure rating (also called increasing the lift), more pitches are added to the pump. All ratings and specifications that relate to pressure in a PCP are based on the cavity-pressure rating, which is an assigned value. The cavity-pressure rating is not modified or adjusted for rotor sizing, operating speed, or fluid viscosity. The cavity-pressure rating dictates the pump model rating, but it does not indicate the capability of the pump model.
Reciprocating Submersible Pump Improves Oil Production
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14966, ’Novel Reciprocating-Submersible-Pumping Technology for Performance Improvements in Oil Production,’ by Zhigang Wang, PetroChina, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.

Submersible pumping by use of a linear motor is crucial for oil production in a low-permeability reservoir, especially in China. However, improving the life, reliability, and performance of the submersible linear motor and reducing energy consumption are challenging. Several novel designs for lubrication, hydraulic buffer, floating suction device, automatic motor drive, and control methods were proposed. The technology is simple to implement and can be adapted to low-production wells, directional wells, and horizontal wells.

Introduction

Rod pumping is a conventional oil-lift method in China, with more than 80% of oil wells across the country using this technique. However, conventional systems are more suited to high-production wells (e.g., in the range of 5–100 m3/d) than to low-fluid-yield wells. Conventional systems have high energy consumption and low efficiency when applied to low-fluid-yield wells such as directional, deviated, or sidetracked wells. Therefore, a rodless pumping technique was developed. In China, approximately 20% of the oil wells use rodless pumping with a nonlinear (rotary) motor, representing 30% of the country’s oil production and accounting for approximately one-third of total energy consumption in oil production. Compared with rod pumping, the rodless technique has lower associated materials costs, less risk, and no issues caused by the accidental dropping of rods and the eccentric wear associated with the conventional rod-pumping method.

Either rotary or linear motors can be used in rodless pumping. The linear motor is a relatively new type of electric motor. The linear motor has its stator and rotor in linear motion to produce a linear force along its length. It is designed to convert electrical energy directly into linear mechanical energy. Although linear motors have been traced back to the 19th century, they are not widely used. Linear motors have been advanced and have proved to be economically viable for industrial application. In 2001, North China Oilfield Company experimented with the linear-motor-pumping technique. The linear-motor-pumping device used a downhole linear motor to lift the oil by reciprocating movement.
New Estimation Technique Shifts Assessment of Global Unconventional Gas Resources
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 148365, ’Global Unconventional Gas Resource Assessment,’ by Z. Dong, S.A. Holditch, SPE, D.A. McVay, SPE, and W.B. Ayers, SPE, Texas A&M University, prepared for the 2011 SPE Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.

As the world reserves of liquid hydrocarbons from conventional reservoirs peak and begin to decline, natural gas will play an increasingly important energy supply role. Most estimates of the original gas in place (OGIP) reported for world unconventional gas start with Hans-Holger Rogner’s 1997 top-down study. That global estimate is most likely quite conservative because the oil and gas industry has discovered enormous volumes of shale gas around the world since the 1990s. The objective of this project was to estimate the probabilistic distributions of original volumes of gas trapped in coalbed, tight sand, and shale reservoirs worldwide.

Introduction

To accomplish this objective, the authors reviewed published assessments of coal and conventional and unconventional resources and established the quantitative relationship between unconventional gas [coalbed methane (CBM), tight sands gas, and shale gas] and the conventional hydro-carbon (coal, conventional gas, and oil) resource endowments for North America. Then, they used this relationship to extrapolate original unconventional gas in place worldwide. For the assessments, P10, P50, and P90 are the values for which the probability is 10, 50, and 90%, respectively, that the value will be exceeded. This work established an unconventional OGIP of 83,400 Tcf (P90)–184,200 Tcf (P10), which is 2.6–5.7 times greater than Rogner’s estimate of approximately 32,600 Tcf.

Global Unconventional Gas Base. According to Rogner’s estimates, world-wide original in-place resources were approximately 9,000 Tcf of CBM, 16,000 Tcf of shale gas, and 7,400 Tcf of tight sands gas. Rogner’s 1997 global estimate is most likely quite conservative, given the recent discovery of significant shale gas around the world.

Resource Triangle. J.A. Masters suggested in a 1979 paper that hydrocarbon resource types can be assigned to various resource classes in a triangular distribution and that their positions in the triangle reflect their abundance, their reservoir quality, and the technology required for recovery (Fig. 1). As one goes lower on the gas resource triangle, the reservoirs are lower grade, which usually means the reservoir permeability is decreasing. These low- permeability reservoirs are much larger than the higher-quality reservoirs.
Exploration Tries To Answer Questions About the Lower Silurian Longmaxi Shale in China
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 14487, ’Sichuan Basin Shale Gas, China: Exploring the Lower Silurian Longmaxi Shale,’ by Claudia Hackbarth, SPE, Danny Soo, and Navpreet Singh, SPE, Shell, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.

Shale-gas exploration in China is already under way and rapidly increasing in activity level. The Sichuan basin, one of the most prolific petroleum basins in China, is at the forefront. However, exploration and assessment of an untested shale-gas play is typically lengthy and expensive. Compared with conventional oil and gas projects, shale-gas projects may require a number of early wells to prove the existence and distribution of the gas but then many more wells to test and optimize engineering techniques until a commercially viable combination is found. This process could be summarized into two overarching questions: “Is there a material amount of gas?” and, if yes, “Can it be produced economically?” 

Sichuan Basin Structure

The topographic Sichuan basin today is a remnant of the originally much larger Upper Yangtze cratonic sedimentary basin (Fig. 1). In the southern Sichuan basin, structures are characterized by thin-skinned faulting and thrusting, often above an Upper Cambrian detachment surface, likely an evaporitic ductile layer that now cores the folds.

The Sichuan-area stratigraphic column contains several potential source-rock intervals. Industry has so far focused attention on the Lower Cambrian Qiongzhusi and the Ordovician-Silurian boundary as potential shale-gas reservoirs.

The Upper Ordovician Wufeng shale and Lower Silurian Longmaxi formation are generally regarded as belonging to the same black-shale succession, but an erosional surface and regional disconformity separate the two intervals. The Longmaxi formation is not as widespread as the Wufeng formation and is restricted to the Yangtze region. From the bottom up, the Ordovician/Silurian succession consists of

A lower graptolite-bearing, black or dark-gray, carbonaceous/siliceous shale (Wufeng formation), generally several meters thick

The Guoyinchao limestone or calcareous siltstone with abundant Hirnantian fauna and other shelly fossils, typically 0.5–3 m thick

The Lower Longmaxi black, graptolite-bearing, carbonaceous/siliceous shale with cherty slate

The Upper Longmaxi gray calcareous mudstones and siltstones, interbedded with an increasing number of thin limestone layers toward the top of the formation

Regional studies indicate that Wufeng and Longmaxi shales were buried deeply enough over a large area of the Sichuan basin to have reached the gas-generation window.
CO2 Enhanced-Oil-Recovery Project Injects New Life Into Madison Reservoir in Wyoming
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152862, ’Beaver Creek Madison CO2 Enhanced-Oil-Recovery Project: Case History - Riverton, Wyoming,’ by Charles A. Peterson, SPE, Edward J. Pearson, SPE, and Veronica T. Chodur, SPE, Devon Energy, and Carlos Periera, M3 Petroleum Engineering, prepared for the 2012 SPE Improved Oil Recovery Symposium, Tulsa, 14-18 April. The paper has not been peer reviewed.

The Madison reservoir, located in the Beaver Creek field, 14 miles south-southeast of Riverton, Wyoming, (Fig. 1) is found at an average depth of 11,235 ft, making it among the deepest CO2 enhanced-oil-recovery (EOR) projects in the United States. The Beaver Creek Madison project is the most recent CO2 EOR project in Wyoming. With a preproject oil production of 43 million bbl, this flood is projected to increase recovery by 11.1 million bbl, or 10% of the estimated 109 million bbl of original oil in place. Early CO2-flood response has been increased production from a preflood rate of 280 BOPD to the current rate of 5,100 BOPD.

Introduction

The Beaver Creek field produces from 12 different formations, ranging from the shallow Lower Tertiary Ft. Union formation at 1,150 ft to the Mississippian Madison formation at depths down to 11,664-ft true vertical depth. To date, the field has produced in excess of 80 million bbl of oil and 800 Bcf of gas. The Madison reservoir itself produced 44.6 million bbl of oil up through the beginning of the EOR flood.

The Madison project, designed as a combination peripheral and gravity-stable CO2 EOR project, began construction in 2007, with initial CO2 injection in July 2008. Since then, production increased from 280 BOPD to more than 5,100 BOPD as of January 2012 and recovered an incremental oil volume in excess of 2.6 million bbl through the end of 2011.

Field History and Madison Development

The Beaver Creek field was discovered in June 1938 with the drilling of the Standolind (Amoco) Beaver Creek Unit (BCU) 1. The well is still active today, having produced more than 38 Bcf and still flowing at 176 Mcf/D.

In January 1954, the Madison reservoir was discovered with the drilling of Standolind’s BCU 30 to a depth of 11,447 ft. The Madison oil-production rate peaked at 8,797 BOPD in November 1962 (Fig. 2). Production remained fairly stable until 1966, when the reservoir’s oil rate began declining while water production increased. Production eventually stabilized in 1999 and remained at approximately 280 BOPD until the beginning of the CO2-flood project. Through this period, the reservoir produced a total of 44.6 million bbl of oil, 12.8 Bcf of gas, and 282.5 million bbl of water.
Comments: Farewell
Authors: Denney Dennis
Published: February 2015

Editor's column

For the past 17-plus years, it has been my privilege to serve as your JPT Technology Editor. After growing up in the oil patch as the son of a sales engineer for a major service company, I have spent all but a couple of years of my adult life as an oily.

When I came aboard JPT, there was this idea of publishing condensed versions of SPE technical papers rather than the traditional full-length, peer-reviewed papers. The plan was to get more important technical information in front of more SPE members more quickly. That was a new type of job for me. I had spent 20 years as a petroleum engineer in reservoir and production engineering with Mesa Petroleum and Maxus Exploration (actually nearly 30 if you count my time as a well tester for Diamond Shamrock—thank you, Bud Reitman, for encouraging me to go back to school to get my PE degree).

The first full year of publishing these synopses (1997), we covered 22 separate topics (coiled tubing, cementing, production operations, etc.) This year, JPT will publish synopses under 46 topics. With the help of Karen Bybee, who retired 2 years ago, and now Adam Wilson, almost 2,500 papers have been presented to you in the pages of JPT. As an SPE member before I began working at JPT, I remember how difficult it was to find and read papers of interest—most of all, there was the lack of time to read full-length papers trying to find information that I could use in my job.

Now, these shortened papers present enough material for busy engineers to determine if the technologies and case studies described are of value. I especially hope that engineers read papers from disciplines other than their primary ones. I am not an educator (I tried it) but my goal at JPT always has been to spread knowledge among SPE members. And it was always my hope that these synopses would pique the interest of readers, allowing them to see the range of possibilities a technology presents and imagine new applications to challenges they were facing.

When taking junior- and senior-level courses in college, we used SPE papers as much as, if not more than, textbooks to learn engineering technology and applications. Since going to work for you here at SPE, I have learned that you can use SPE papers to expand your knowledge exponentially. A great advantage of SPE is access to the breadth of technology available in the papers, from the simplest applications to the most highly technical. Almost every engineering discipline is represented here. Besides petroleum technology, information in the construction, marine, civil, structural, safety, mechanical, electrical, and other sectors is represented.