bluuebunny/crossref_metadata_2025 huggingface dataset:
Multiwell Case Study - Increasing Oil Production in a Mature Field With Rigless Intervention
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 11644, "Increasing Oil Production in a Mature Field by Rigless Intervention-A Multiwell Case Study," by Vivek Garg, ONGC, and Shubhranshu Ashesh (now with Shell), SPE, Kapil Seth, SPE, and Amit Govil, SPE, Schlumberger, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4-6 December. The paper has not been peer reviewed.

Reviving production from brownfields is a major focus for oil and gas companies. Workflow and procedures are outlined that were adopted to increase oil production from seven wells by use of rigless intervention on an offshore platform off the west coast of India.

Introduction

The field was discovered in 1987 and was put on production in 1994. The main reservoir is a Middle Eocene carbonate deposit characterized by vugs, dissolution channels, and fractures (both vertical and horizontal). Hence, high-permeability streaks provide conduits for early water breakthrough, which has been primarily responsible for the decline in oil production. The average water cut in the field is 80%.

The offshore platform posed a special challenge because of its proximity to two water-injector platforms. Injection-water accumulation in the drainage zone covered by the wells of this platform was determined by current temperature anomalies and salinity contrast between the formation water and the accumulated injection water in the vicinity of the wells. The challenge was to study the flow dynamics so that additional perforations in the bypassed section would yield water-free oil.

Method

The strategy included well diagnostics followed by workover intervention to increase oil production and reduce the water cut. Production logging identified the flow profile. Then, pulsed-neutron logging was performed where required to determine hydrocarbon (HC) saturation in the cased-hole environment. Integration of data from openhole logs, production logs, and pulsed-neutron spectroscopy helped identify depleted zones and zones of bypassed oil. Through-tubing isolation plugs were placed to isolate water-producing intervals. Oil in bypassed zones was accessed with additional perforations. Formation-water salinity was calculated from pulsed-neutron logging to identify zones of injection-water breakthrough. Such intervals were avoided when adding new perforations.

Seven intervened wells yielded a 53% increase in oil production to 2,708 BOPD. The average water cut of the platform decreased from 80 to 76%.

Candidate Selection

The objective of the operation was to increase oil production while minimizing water and gas production. Because no rig was available, operations had to be carried out with a modular skid unit, which constrained available tools and methods.
Increasing and Enhancing the Supply of Petroleum Industry Talent
Authors: Sprunt Eve S. , Simon Monique , Thorness Steve , Musson Paul
Published: February 2015

Talent & Technology

Much has been written about the big crew change. Hiring and retaining the next generation is now a top issue for the industry. Energy supply and demand is one of the critical issues facing this generation. While alternative energies and conservation may mitigate some of the supply and demand challenges, petroleum will play a major role in powering societies for the foreseeable future. To meet this challenge takes people. And not just any people. It takes talented, highly educated, and motivated engineers and scientists to find, develop, and produce hydrocarbons.

Recognizing this people challenge, 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 enhance the quality of talent available to our industry. This involves increasing the number of students interested in the energy industry, enhancing the quality of educational programs worldwide, and encouraging graduates to pursue a career in the oil and gas industry.

To better understand what factors are important in the attraction and retention of young people, the SPE Talent Council had SPE Market Research conduct a survey of SPE members below the age of 35, who are not currently students. Invitations to participate in the survey were sent to 8,833 members in February and March 2008 and 1,711 (19.3%) responded. The distribution of the respondents’ regions of origin is shown in Fig. 1.

More than half of the respondents hold a minimum four-year university degree (52%), while another 40% hold master's degrees, and 7% have a doctorate. The most common university discipline is petroleum engineering at 46%, followed by mechanical engineering and chemistry/chemical engineering at 15% each. This discipline distribution is not surprising since those polled are all members of SPE. The next most common discipline for those who replied is geology at 5%. A multitude of disciplines make up the remaining 19%. Men are the overwhelming majority at 79% of the total.
Comments: Betting on Gas
Authors: Donnelly John
Published: February 2015

Editor's column

ExxonMobil’s purchase of XTO Energy last month—one of the largest merger and acquisition deals this decade—is another sign that future prospects for gas appear brighter than ever. The supermajor’s buyout of a leading developer of unconventional gas resources in North America gives it a major foothold in what has become the hot E&P play of the moment. 

In a panel session at last month’s International Petroleum Technology Conference (IPTC) in Doha, Thomas Walters, president of ExxonMobil Gas and Power Marketing, laid out his company’s view of the future of gas, a week before the XTO deal was announced. Gas demand will see strong growth over the next 20 years and resource holders must find new ways of developing supplies to meet this demand, he said. Presenting information from ExxonMobil’s 2009 Energy Outlook, Walters said that fossil fuels would continue to be the main energy source for decades and that gas demand would grow faster than demand for other hydrocarbons. 

Global demand for natural gas will challenge the industry to deliver, from developing unconventionals such as shale to massive liquefied-natural-gas (LNG) projects, such as those that have been built in Qatar, panelists said during the IPTC session. Gas, in particular, will play an important role in the future energy mix because of its abundance, smaller environmental impact, and its desirability as a fuel for power generation.

Since its founding in the mid-1980s, XTO has grown by acquiring mature assets and expanding reserves through technology know-how. It owns large interests in major US shale, tight gas, and coalbed methane plays, and has reserves estimated at 45 Tcf of gas equivalent. ExxonMobil said it plans to create an upstream organization to manage global unconventional resources. Other companies are betting on a bright future for unconventionals as well. BP, Statoil, and Eni all have bought significant shale gas assets in the US in the past year. And Devon Energy announced in November that it was selling all of its Gulf of Mexico and non-North American E&P assets to focus on US and Canadian onshore. Devon holds key stakes in several of the largest US shale plays. 

Although projects in North America have drawn the most attention, other regions have begun estimating the huge potential of unconventional resources. Poland has attracted the interest of Marathon and ConocoPhillips for potential shale development. Saudi Arabia is also eyeing tight gas and shale projects, Abdulla Al-Naim, vice president of Exploration with Saudi Aramco, said during IPTC. He predicted that the exploration staff of the future would be focused on unconventionals.

The rise of gas as a future fuel source continues to boost the prospects of a global gas producers’ association similar to OPEC. The 11 member countries of the Gas Exporting Countries Forum met in Doha during the week of IPTC to discuss strategy. Although gas has had limited scope as a global commodity, the growth of LNG has contributed to gas becoming a more fungible and less regional commodity.
Technology Focus: Mature Fields and Well Revitalization (January 2010)
Authors: Ali Syed A.
Published: February 2015

Technology Focus

The focus on finding and developing new fields sometimes overshadows attempts to recover more hydrocarbons from brownfields. Nevertheless, innovative projects are being implemented around the world to revitalize mature oil and gas fields.

Every mature field has unique characteristics, and often several viable options are available for revitalization. Once a decision is made to implement a particular revitalization option, it is very expensive to change course and attempt an alternative solution. Therefore, it is imperative to minimize the risk of pursuing a wrong alternative. Simulations and pilot projects can generate data to narrow down options. However, economic constraints may limit actual data gathering. Thus, previous experience in revitalizing similar types of fields can be very leveraging.

Archived SPE papers can be used to identify and rank revitalization alternatives. These papers can provide useful details regarding the challenges and success of hundreds of revitalization techniques. Furthermore, recent SPE papers include current details on the use of best-available technology to revitalize mature fields effectively around the world. The revitalization techniques presented in these papers may be well-established techniques, but much can be learned by reviewing the approach taken to investigate potential solutions, the types of options considered, and the progression from ideas to realities.

Mature Fields and Well Revitalization additional reading available at OnePetro: www.onepetro.org

SPE 124605 • “Forties: Creating a Long-Range Development Plan for a Large, Mature, Complex North Sea Oil Field” by Alan Chesterman, Apache North Sea, et al.

SPE 122402 • “Optimizing the Development Concept of a Mature Gas Field in Intensive-Drilling Context: Tunu Field Case” by Bhayu Widyoko, Total, et al.

SPE 122338 • “Optimizing Horizontal-Well Placement and Reservoir Inflow in Thin Oil-Rim Reservoirs Improves Recovery and Extends the Life of an Aging Field” by G. Kartoatmodjo, Petronas, et al.

SPE 124647 • “Mature-Field Production Optimization Through Standardization of Operating Procedures for Reservoir Monitoring” by Vikas Bhushan, Shell, et al.
Casabe Mature-Field Revitalization Through an Alliance: A Case Study of Multicompany and Multidiscipline Integration
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 122874, ’Casabe Mature-Field Revitalization Through an Alliance: A Case Study of Multicompany and Multidiscipline Integration,’ by L. Marquez, SPE, J. Elphick, SPE, and J. Peralta, Schlumberger, and M. Amaya and E. Lozano, Ecopetrol S.A., prepared for the 2009 SPE Latin American and Caribbean Petroleum Engineering Conference, Cartagena, Colombia, 31 May-3 June. The paper has not been peer reviewed.

The achievements of an alliance between Ecopetrol S.A. and Schlumberger to revitalize the Casabe field, a mature field in Colombia, are highlighted. Challenges were multifaceted in this mature complex field. Some related to the heterogeneous nature of the reservoirs, limited sand continuity, unfavorable mobility for the ongoing waterfloods, associated sand production, and wells lost because of collapses.  

Introduction

The Casabe field, discovered by Shell in 1941, is in the Mid-Magdalena Valley basin in Colombia and contains 1,120 wells. Cumulative production was 284 million bbl of oil as of December 2007. The productive-formation depths range from 2,200 to 5,500 ft. The production peaked at 46,000 BOPD in 1953 and achieved a primary recovery factor of 13% under natural mechanisms. Since 1985, the field has been under waterflood, which increased recovery to 19.8%. Waterflooding has been a challenge because of the very heterogeneous nature of the reservoirs, sand-continuity complexity, oil viscosity, sand production, and wells lost to collapses.

Since 2004, the alliance has worked to revitalize this mature field to increase its value by use of field management. A joint team was assembled to determine key factors related to the past behavior. This method provided the best way to improve future management practices and increase production. Key factors to be managed in the Casabe field are the waterflooding behavior, casing-collapse mechanisms, and sand-production problems. The team developed analytical and numerical models to understand these issues. Some of the models were complemented with laboratory analyses along with well tests. All areas are integrated within the reservoir-management philosophy, which means they are all interrelated.

Casabe Field: History vs. Future

Initially, the Casabe field was under-saturated and produced under primary mechanisms (mainly natural depletion) until the mid-1980s when a waterflood was initiated. Most of the gas had already been produced, and oil rates were down to 10 BOPD/well. The waterflood tripled the per-well oil production, but many inefficiencies remained, which made it difficult to obtain better performance.
The Future of Shelf Plays for Midsized and Independent Operators
Authors: Broussard Earl
Published: February 2015

Guest editorial

For several years, medium and large operators have focused on pushing the technological boundaries in deepwater development, particularly in the Gulf of Mexico. However, the recent Macondo incident in the Gulf and the subsequent drilling moratorium caused some introspection for these operators. It has given rise to questions such as, “Am I risking the company by pushing the deepwater envelope?” and “What if I have a major spill or blowout?”

Today, independent and medium-sized operators are concerned about the commercial risks of deepwater drilling, but they are equally concerned about the commercial risk of operations outside the United States. The solution for many is refocus back to the shelf.

For many years, the service industry focused many of its resources and development efforts on deepwater and high-pressure technologies, leaving the industry underserved in terms of hardware and technology availability for shallow water jack-up shelf activities. Over the decades, technology applicable for shallow water use has taken a back seat commercially. With multinational manufacturers focused globally on large deepwater projects, often these small shelf fields have not received the technology attention necessary to bring a commercial small development to market.  

Developing Marginal Fields

In the past few years, the industry has begun to revisit the technology requirements for marginal field development. With new technology, many marginal shallow water reserves that were once overlooked because they were uneconomic to exploit at the time now appear more attractive. However, the game needs to change. New technology will need to be coupled with fast-track development as the hallmark. The commercial aspects with risk avoidance will become the protocol for these marginal fields.

When evaluating the viability of these projects, oilfield companies will be driven by three critical metrics: risk, project cash requirements, and net present value (NPV) calculations. In simple terms, they authorize the project based on its risk assessment, costs, and on the revenue stream and schedule for first oil or gas. 

Integrated and non-integrated oil and gas companies work from project profitability models involving NPV modeling. Execution of these basic metrics is essential to project profitability and funding. Keeping profit growth moving positively allows access to future capital. This is the model for large and small oil and gas companies alike. This principle drives all major oil and gas companies to opt for larger reserves and pass over smaller fields—and it creates a niche for non-integrated companies that are interested in capitalizing on smaller fields with less risk of development.
Technology Focus: EOR Performance and Modeling (January 2011)
Authors: Bai Baojun
Published: February 2015

Technology Focus

SPE hosted two enhanced-oil-recovery (EOR) conferences in 2010: One was the 2010 SPE Improved Oil Recovery Symposium in Tulsa and the other was the 2010 SPE EOR Conference at Oil & Gas West Asia, Muscat, Oman. Many other SPE conferences had sessions on EOR technologies. Therefore, it is not surprising that more than 350 papers were presented on the topic in the past year. These papers covered past field-application experiences and accomplishments, current strides, and future directions.

As in previous years, when I selected papers to highlight EOR this year, I classified the papers into the categories of gas injection, chemical methods, thermal methods, conformance control, microbial EOR, carbonate-reservoir EOR, reservoir-problem-identification technologies, and novel EOR methods such as low-salinity waterflooding and nanoparticles for EOR. However, it was still quite difficult to select only four to highlight from so many outstanding papers. In the past few EOR features, I highlighted chemical methods, CO2 EOR and sequestration, low-salinity waterflooding, particle gel for conformance control, wettability alteration, and methods to identify reservoir channels. Even though those topics are still quite important and many new ideas and information were presented this year, I decided to give preference to topics not highlighted before and to papers that comprehensively summarize field experiences.

Overall, the leading-edge EOR technologies presented in SPE meetings this past year will be applied increasingly on a global scale and will increase the oil recovery of mature oil fields significantly as the technologies mature.

EOR Performance and Modeling additional reading available at OnePetro: www.onepetro.org

SPE 133089 • “Rock/Fluid Characterization for Miscible-CO2 Injection: Residual-Oil Zone, Seminole Field, Permian Basin” by M.M. Honarpour, SPE, Hess Corporation, et al.

SPE 129899 • “Potential for Polymer Flooding Reservoirs With Viscous Oils” by R.S. Seright, SPE, New Mexico Petroleum Recovery Research Center. See SPE Res Eval & Eng, August 2010, page 730.

SPE 132487 • “Air Injection in Heavy-Oil Reservoirs—A Process Whose Time Has Come (Again)” by M.G. Ursenbach, SPE, University of Calgary, et al. See J Can Pet Technol, January 2010, page 48.

SPE 129925 • “Nanoparticle-Stabilized Supercritical CO2 Foams for Potential Mobility-Control Applications” by David Espinosa, SPE, University of Texas at Austin, et al.

SPE 129692 • “Demonstration of Low-Salinity EOR at Interwell Scale, Endicott Field, Alaska” by Jim Seccombe, SPE, BP plc, et al.

SPE 139667 • “Tertiary Oil Recovery and CO2 Sequestration by Carbonated-Water Injection” by N.I. Kechut, SPE, Heriot-Watt University, et al.

SPE 132359 • “Identifying Injector/Producer Relationships in Waterflood Using Hybrid Constrained Nonlinear Optimization” by H. Lee, University of Southern California, et al.
Technology Focus: Mature Fields and Well Revitalization (January 2011)
Authors: Ali Syed A.
Published: February 2015

Technology Focus

Growth in oil and gas production must stem from a combination of new-field development and effective management of existing fields. Substantial additional reserves can be secured by enhancing the recovery from mature fields. Many operators are aggressively pursuing a strategy that is based on tapping bypassed horizons, cutting costs, and implementing leading-edge technologies to combat the natural decline of mature fields.

Field exploitation strategies such as resource-targeted infill drilling, field- or play-extension wells, and strategic recompletion, the locations of which are based on integrated-characterization studies, are the preferred approaches to revitalization of mature fields. Reserves growth is enhanced further by deployment of advanced characterization technologies such as 3D seismic that enable better definition of the structural framework of a mature field, enabling targeting of depositional axes for strategic infill drilling.

An integrated approach built on the latest reservoir-management and production-enhancement techniques promises to accelerate the revitalization of mature fields. Production-enhancement techniques such secondary and tertiary schemes, horizontal and multilateral drilling, improved perforation and stimulation methods, new completion techniques, advanced logging procedures, artificial-lift optimization, and water control can boost the recovery from mature fields.

Papers selected for this feature are aligned with the aforementioned theme of integrated reservoir management and production enhancement.

Mature Fields and Well Revitalization additional reading available at OnePetro: www.onepetro.org

SPE 134061 • “An Integrated Analytical Method for Identifying Remaining Potential of a Thin-Bed Reservoir in a Deltaic System—Sengata Field” by Riswan Kiay Demak, Pertamina, et al.

SPE 135921 • “Technological Solutions for Marginal-Oilfield Development” by Ravil R. Ibatullin, SPE, TatNIPIneft, et al.

SPE 128448 • “Optimizing Simulation Studies for Gas/Condensate-Field Development and Management” by Ahmed El-Banbi, SPE, Cairo University.

SPE 132187 • “Using Drilling and Logging Data for Developing 1D Mechanical Earth Model for a Mature Oil Field To Predict and Mitigate Wellbore-Stability Challenges” by M. Afsari, Iranian Offshore Oil Company, et al.
Technology Focus: Well Control (January 2011)
Authors: Schubert Jerome
Published: February 2015

Technology Focus

As a well-control instructor and researcher for the past 20 years, I am often surprised that some in our industry have the opinion that “well control” begins with the occurrence of a kick and ends when the kick has been killed, when in reality, well control begins when the well location is selected. Every decision after this point must consider controlling formation pressures to prevent any unintended influx into the wellbore, buildup of annulus pressure, and uncontrolled flow of wellbore and formation fluids during the drilling, completion, and production operations and even after the well is plugged and abandoned. Serious well-control incidents can occur any time after the well is spud in, even when least expected.

Two recent incidents in the Gulf of Mexico remind us of this fact. The first that I will mention is the BP Macondo blowout. Because this incident has been covered thoroughly by the media, all I will say is, “Could part of the reason for loss of control be that the crew thought that just because casing had been set and cemented that nothing could happen and then when it did, it caught them off guard?” This example is a vivid reminder that once casing is installed and cement is pumped, the danger is not over.

The other incident never made the news because there was nothing spectacular about it—no injuries, no explosion, and no release of oil into the Gulf. This incident was mentioned briefly at the 2010 Decommissioning Summit, Gulf of Mexico. I bring it up to point out that, even though the industry as a whole exceeds mandated plugging requirements, things still can go wrong. As was stressed at the summit, industry needs to think of plugging as a business, not just an expense at the end of the life of the well. After all, we intend for the plugs to last for eternity.

Well Control additional reading available at OnePetro: www.onepetro.org

SPE 130693 • “Snubbing Units Used Effectively in Well-Control-Recovery Efforts” by S.R. Wehrenberg, SPE, Boots & Coots, et al.

SPE 133027 • “Key-Factor Sensitivity Analysis on Blowout Probability in Dangerous Drilling Conditions—Applying Different Technical Solutions” by S. Masi, Eni E&P, et al.

SPE 131332 • “Drilling Through Gas-Hydrate Sediments: Managing Wellbore-Stability Risks” by T. Khabibullin, SPE, Texas A&M University, et al.
Behavior and Shape of Gas Kicks in Wellbores
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 128276, ’Behavior and Shape of Gas Kicks in Well Bores,’ by H.F. Spoerker, SPE, OMV E&P, and T. Tuschl, SPE, Leoben University, originally prepared for the 2010 IADC/SPE Drilling Conference and Exhibition, New Orleans, 2-4 February. The paper has not been peer reviewed.

The full-length paper describes the driving mechanisms of gas entering into the wellbore and the methodology used for simulating and visualizing the percolation of gas after the well has been shut in. It is part of a multi-year research project with the goal of understanding the wellbore/gas-influx system in more detail. 

Introduction

While of lesser importance for the volumetric and hydraulic calculations required in well-control operations, understanding of shape and distribution of gas bubbles in the annulus during a kick bridges the gap between the hydraulic and the chemical processes happening in the wellbore. Until now, representation of the total gas influx volume as one single-phase, dry-gas “bubble” slowly moving up the shut-in wellbore (i.e., annulus) can be found in many well-control models.

Starting in the late 1960s, and especially in the late 1980s and early 1990s, efforts were made to better simulate and measure the behavior of gas kicks in wellbores. These projects could be divided into two groups: (1) the theoretical approach using mathematical concepts and material-balance equations to simulate gas behavior and (2) the practical approach of building several test facilities and flow loops to measure gas behavior under “real” conditions All of these projects attest to the assumption that gas entering the well-bore will not accumulate as one major void fraction. Depending on different factors such as geology, mud rheology, and differential pressure between formation and wellbore, it can be assumed that gas—in contrast to prior assumptions—once having entered the wellbore remains dispersed in the form of multiple small bubbles slowly percolating upward.

Formation/Wellbore Interaction

Common reservoir-engineering theory explains the movement of gas through a porous medium, in its simplest form adequately represented by the Darcy equation and relating the volumetric flow through a porous medium to the differential pressure applied, the cross-sectional area and length of the rock volume, the dynamic viscosity of the fluid, and the permeability of the rock. Applying Darcy’s law for radial flow, the flow rate for a reservoir/wellbore system at a given differential pressure can be calculated, assuming conventional sandstone reservoirs.

While permeabilities for such reservoir rocks are typically in the range of 0.01 to 1 darcy, secondary-porosity fracture systems in limestones and dolomites will behave in a radically different way and can exhibit effective permeabilities of the fracture systems several orders of magnitude higher than those of conventional sandstones.
Trends in Monitoring: How to Use Real-Time Data Effectively
Authors: Pritchard David , Roye Jesse , Cunha J.C.
Published: February 2015

Management

Real-time data is not about well control, it is about well control avoidance. Recent catastrophic blowouts have underscored the value of real-time data and, more importantly, they have also underscored the value of having the right kind of experience to understand well data interpretation in real time.

What is the well telling us? How do we use real-time data to ensure a stable wellbore? Real-time monitoring integrated with rigorous total well control analysis is required to embrace and achieve continuous improvement and ensure the safest possible environment. Next generation monitoring requires a step change that includes hazards avoidance as a precursor to drilling optimization.

Real-time data can be used effectively to avoid, minimize, and better manage drilling and completion operations. They can also provide the foundational support to improve training in the industry as well as develop hands-on simulators for hazards avoidance.

The fundamental definition of process safety is that of ensuring containment. In the case of drilling and completion operations, that means well control. Process safety management (PSM), a regulation promulgated by the US Occupational Safety and Health Administration, is an analytical tool focused on preventing release of any substance defined as “highly hazardous.” This concept can be extended to oil and gas well operations within the context of ensuring that the well is constantly under control. The industry has pursued personal safety, which resulted in significant improvement in preventing accidents commonly referred to as “slips, trips, and falls.” Though this is a notable accomplishment, it had no influence on well control episodes, and blowouts remained a frequent occurrence. As well complexity increases, well control events increase disproportionally. Even the term well control, which should be related to the performance of oil well operations in a controlled manner, became more associated with the operations necessary to fix a situation once control was already lost.

Often, the industry depends on blowout preventers as execution tools rather than the fail-safe tools they were designed as. If a driver constantly slams on the brakes of a car at high speed, eventually the brakes fail, or at the least, fail to operate in a timely manner or accurately.

Real-time data offers the ability to ensure process safety. Fig. 1 shows the relationship between real-time data and its impact on operational outcomes.
EOR Potential in the Middle East: Current and Future Trends
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 143287, ’EOR Potential in the Middle East: Current and Future Trends,’ by Saad M. Al-Mutairi, SPE, and Sunil L. Kokal, SPE, Saudi Aramco, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed.

The number of enhanced-oil-recovery (EOR) projects in the Middle East (ME) has increased over the past decade. This is a review of current ME EOR projects, from full-field developments to field trials. The option of advanced-secondary-recovery, or improved-oil-recovery (IOR), technologies before full-field deployment of EOR can be a better first option before deployment of capital-intensive EOR projects. The ME’s general drive toward ultimate oil recovery instead of immediate oil recovery is highlighted in the context of EOR. 

Introduction

The EOR process is a tertiary oil-recovery method representing the last stage in a field’s life. Fig. 1 shows the definition of various oil-recovery terms. Primary and secondary recovery (conventional recovery) target the mobile oil in the reservoir, and tertiary recovery, or EOR, targets the immobile oil (cannot be produced naturally because of capillary and/or viscous forces).

Primary-, secondary-, and tertiary-recovery methods follow a natural progression of oil production from the start to a point at which it is no longer economical to produce the hydrocarbons. EOR processes attempt to recover oil beyond secondary methods. Recovery, especially EOR, depends on the oil price and overall economics. On aver-age, the worldwide recovery factor from conventional (primary and secondary) recovery methods is approximately one-third of that originally present in the reservoir. This factor implies that the target for EOR is substantial (two-thirds of the resource base). Improving the recovery factor can be achieved by deploying advanced IOR technologies while using best-in-class reservoir management practices, and by deploying EOR technologies.

There are 11 EOR projects kicked off, on pilot, or at commercial scale in the ME. Oman is taking the lead in the implementation of EOR projects because of its declining oil production. The urgency of EOR implementation in the ME is a function of declining oil-production rates, availability of remaining “easy oil,” impending momentum to contain CO2 (starting early with the long lead times for such projects), and other geopolitical factors.
CUBE - A New Technology for the Containment of Subsea Blowouts
Authors: Andreussi H.P. , De Ghetto G.
Published: February 2015

Young Technology Showcase

After the Macondo incident, the oil industry started a significant review of its capabilities to respond to a subsea well blowout and launched some specific development projects. Eni decided to participate in the principal joint industry projects launched on this topic, and also started internal activities aimed at the development of new containment methods.

Two years after Macondo, it is clear that the major containment method of a subsea blowout relies on the use of a capping stack. This can be deployed in water depths as deep as 3000 m and equipped with multiple outlets that allow liquid and gaseous hydrocarbons to be routed to surface.

However, in some cases well capping cannot be applied when a) well-integrity issues arise, this may happen when the capping stack causes a substantial pressure increase at the wellhead, with a potential rupture of the casing and the lateral dispersion of well fluids; b) the blowout preventer (BOP) stack is not accessible because of mechanical problems (status of wellhead/BOP or irremovable debris); c) the blowout does not come directly from the well (i.e., from nearby sea lines or mud line). On the basis of these and similar considerations, it is quite clear that the containment of a blowout event cannot only rely upon the use of a capping stack and other methods must be available.

Eni has been working in the last 2 years on a new concept with the support of TEASistemi, a research company of the University of Pisa, developing an alternative to the capping technology. This system is based on the use of an open-sea containment system, which is able to perform at least partial gas/liquid separation. After separation, most of the liquid hydrocarbons plus a minor amount of seawater are pumped to surface. The gas phase can be sent to surface through a separate riser or can be discharged at sea. In order to prevent hydrate formation within the separation system, there must be a low separator-residence time. The system conceived by the authors of this paper has been patented in June 2010 (De Ghetto and Andreussi, 2010) and the first tests were performed in September 2010 at the TEASistemi Laboratory in Pisa.

Of course the concept of subsea phase separation is not new for the oil industry, but up to now it has not been adopted for the containment of subsea blowouts. The reason probably being that up to the Macondo incident, it was believed that subsea collection and transmission to surface of blowout fluids could be easily accomplished by some type of containment dome. Unfortunately, the Macondo incident showed that this is not always the case and that the use of a containment dome presents a number of potential problems which need to be faced, such as the formation of hydrates, the poor control of the system, and finally, issues associated with large fluxes of seawater into the dome.
Case Studies Examine Exploitation Strategies for Development of Mature Gas and Oil Fields
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23373, ’Exploitation Strategy in the Development of Mature Gas and Oil Fields: Case Study,’ by Gina Vega Riveros, Reservoir Consultant, and Emad Yehya, Smoothwell Oil Services, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed. Copyright 2012 Offshore Technology Conference. Reproduced by permission.

Two case studies examine the creation of strategies for the development of mature gas/condensate and oil fields. For the gas/condensate field, the integration of geologic, seismic, production, and reservoir data identified new opportunities for drilling. For the oilfield case study, it is clear that the strategy of exploitation can be improved. According to study results, the oil and gas condensate in place have been increased by 9% and 22%, respectively, compared with the official reserves estimates.

Gas/Condensate Case Study

Geologic Framework. The gas/condensate reservoirs are in the Roble, San  Joaquin, and Guario fields, approximately 11 km southwest of Anaco, Venezuela. The geological model in the Guario 3 reservoir allowed for the integration of four reservoirs as a unique hydraulic unit (Fig.  1). Geologically, the study area is within the greater Oficina area, on the south flank of the Eastern Venezuela basin.

The Merecure formation is Oligocene to early Miocene and was deposited in a transitional environment, yielding sandstones with good lateral extension.

Petrophysics. In Guario 3, ME-G and ME-H sands have an average effective porosity of 14%. Permeability ranges from 20 md to more than 70 md. The water resistivity of 0.1 Ω·m, cementation exponent of 2.00, saturation exponent of 2.00, and shale volume cutoff of 40% were obtained from field data. Both ME-G and ME-H sands showed similar petrophysical properties.

Reservoir Properties. The northwest-ern crest of the Guario 3 reservoir is defined as gas/condensate crude. The eastern part contains a volatile zone of medium gravity with a high concentration of paraffin. The integrated static and dynamic models validated the existence of an areal and vertical communication of four reservoirs into a unique reservoir named Guario 3 (G-3).

Geochemical Study. To verify vertical and lateral reservoir communication between ME-G and ME-H sands, gas chromatographic correlations of samples from wells in different reservoirs were used to establish a clear vision about fluid communication.

Correlations for Predicting Gas/ Condensate Reservoirs. Many empirical correlations have been reviewed in the literature, and they take into account retrograde condensate. The average ranges for applying the correlations and the equations used can be found in the complete paper. Using the correlations, the original gas condensate in place was 1226.84 billion scf, which was considered satisfactory in comparison with the volumetric method of 1267.37 billion scf.
Reducing Uncertainty to Ensure Future Asset Performance
Authors: Ketelaars Frank
Published: February 2015

Guest editorial

Over the past 5 to 10 years, there has been an increasing focus in the offshore oil and gas industry on predicting and quantifying an asset’s expected production performance. This “performance risk” has always been considered one of the key risk factors for an offshore development, in addition to subsurface, economic, safety, and environmental risks. However, with the shift of offshore developments to harsher environments and deeper water, the traditional method of estimating expected availability and production performance figures, using extrapolated data from previous experience, is increasingly considered insufficient.

With increased investment required for some of the ambitious new offshore developments (floating liquefied natural gas [FLNG], Arctic, and ultradeep developments), there is growing pressure to address any risk to the bottom line and understand how the impact of changing environments and operating conditions will affect economic return and expected revenue. As a result, most operators are now adopting more robust methodologies, such as using simulation technology tools, to evaluate and predict expected performance.

Several key areas in the offshore industry illustrate where these “new” production risk factors are especially relevant.

The subsea industry, in particular, continues to undergo rapid transformation as it seeks to exploit untapped reserves. Subsea fields exploited since the late 1990s in the North Sea, US Gulf of Mexico (GOM), and offshore Brazil are now considered areas using proven technology and their performance is well understood. However, pushing subsea developments into ultradeep locations does result in additional performance risk. The 2010 Macondo accident in the GOM clearly showed that the potential impact and escalation of subsea failures or incidents can be dramatically increased because of high water depths. The ultradeep environment will affect potential diagnostics options (Is there a leak? Where is it coming from?), and mitigation and repair options (What intervention activities are possible? Which vessels are available at short notice?). A relatively minor failure, which could have been addressed quickly by divers or remotely operated vehicles in shallower waters, can potentially result in long well or even field outages. In addition, public scrutiny concerning any potential environmental impact would make it likely that operators would now opt for conservative decisions (e.g., a shutdown) in the event of any uncertainty about potential subsea leaks or failures.
The Quadruple Bottom Line (February 2004)
Authors: Baker Kate H.
Published: February 2015

President's column - No abstract available.
Software Application Optimizes Well-Planning and Risk-Assessment Process
Authors: JPT staff _
Published: February 2015

Technology Update - No abstract available.
Optimizing the Organizational Design of a Typical Upstream Exploration and Production Company
Authors: Rabbino Hal , Dunham Cleon , Ritchie-Dunham James
Published: February 2015

Management - This is an edited version of SPE 84437, which was prepared for presentation at the 2003 SPE Annual Technical Conference and Exhibition held in Denver during 5-8 October.
Drilling Technology: New Downhole Tool Reduces Equivalent Circulating Density
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 79821, "A New Downhole Tool for ECD Reduction," by P.A. Bern, SPE, BP plc; Dave Hosie, SPE, and R.K. Bansal, SPE, Weatherford; Donald Stewart, Rotech Engineering; and Bradley Lee, SPE, Weatherford, prepared for the 2003 SPE/IADC Drilling Conference, Amsterdam, 19-21 February.
Drilling Technology: High-Strength 5 7/8-in. Drillpipe
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 79872, "Performance-Driven Drilling-Tubular Technologies," by R.B. Chandler, SPE, and M.J. Jellison, SPE, Grant Prideco; M.L. Payne, SPE, BP plc; and J.S. Shepard, GlobalSantaFe, prepared for the 2003 SPE/IADC Drilling Conference, Amsterdam, 19-21 February.
Overview: Offshore Facilities Construction and Design (February 2004)
Authors: Valenchon Claude
Published: February 2015

Overview - No abstract available.
Well Testing: Analysis of Well-Test Responses in Gas/Condensate Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 81039, "A Novel Methodology for the Analysis of Well- Test Responses in Gas/Condensate Reservoirs," by K. Barrios (now with PDVSA), G. Stewart, SPE, (also with Edinburgh Petroleum Services), and D.R. Davies, SPE, Heriot-Watt U., Edinburgh, prepared for the 2003 SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad, 27-30 April.
Overcoming the Oil and Gas Talent Void By Focusing on the Core Business
Authors: Swanson Charles
Published: February 2015

Playing to its core strengths is generally a sound strategy for any company, in any industry. But it is especially important now for oil and gas companies, when technical and scientific talent in the oil patch is so hard to come by. The oil and gas work force has been declining steadily for almost 20 years. During that time, many companies that should have been competing vigorously for the dwindling resource of human capital instead found themselves staffing up in noncore functions.

Supply and Demand Leads to…Bust?

Other industries have had their slumps, but the bust that hit the oil and gas industry in 1986 was unusually severe and has left long-lasting marks. When commodity prices collapsed, technical, professional, and field workers were forced to leave the industry by the hundreds of thousands. Hundreds of companies disappeared, and in many cases they were acquired by larger competitors. The most striking way in which the oil and gas slump of 1986 was quite different from that which affected other industries is that when the recovery came, workers who had been forced to leave did not return. More alarmingly, they were not replaced with new talent either.

The reasons were numerous. Chief among them was the intensely cyclical nature of the industry and the depth of the downside. People were no longer willing to weather the cyclical nature of oil prices. Also responsible were the explosion of information technology, the advent of the Internet, and the subsequent boom in high-tech, high-paying jobs in this hot new industry. The best and brightest technical and professional workers now had more options than ever before.

Of course, one also needs to be honest about the image problem. Negative portrayals of the oil and gas industry in the media and political circles undoubtedly caused many qualified young workers to take their talents elsewhere. According to the U.S. Bureau of Labor Statistics, there were approximately 33,000 petroleum engineers in the United States in 1983. By 2002, that number had dropped 45% to 18,000. The numbers for geologists and geophysicists are similar—from 65,000 in 1983 to 48,000 in 2002, a drop of 26%. Conversely, the number of computer systems analysts exploded from 276,000 in 1983 to 1.7 million in 2002—a growth of 531%.

While young people were choosing different career paths, the oil and gas workers who entered the work force in the 1960s and 1970s—and survived the 1980s—continued to shepherd the industry through turbulent times. They are now either retired or nearing retirement age, leaving the industry with a serious lack of manpower.
Continuous Borehole-Curvature Estimates Based on Downhole Bending-Moment Measurements
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90794, "Continuous Borehole-Curvature Estimates While Drilling Based on Downhole Bending-Moment Measurements," by G. Heisig, SPE, Baker Hughes Inteq; G. Cavallaro, Eni SpA Div. E&P; and P. Jogi, SPE, J. Hood, SPE, and I. Forstner, SPE, Baker Hughes Inteq, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

A downhole bending-moment measurement combined with a simple mathematical model can provide a good estimate of well-bore curvature, matching results obtained from survey-data analysis well. The bending-moment measurement delivers well-bore-curvature information at a much higher resolution than the standard minimum-curvature method that assumes a constant curvature between survey stations.

Introduction

Any drilling bottomhole assembly (BHA) in a directional wellbore is subjected to bending moments caused by side forces acting on the BHA. These side forces may be caused by gravity, by dynamic effects, or by wall contacts of the BHA in curved wellbore sections. Mathematical models have been developed to predict the side forces, bending moments, and stresses that are introduced into a BHA by a given borehole-curvature profile, usually derived from measured survey data.

The full-length paper discusses application of mathematical models to predict the borehole curvature from measured bending-moment data. The bending-moment data were acquired with a recently introduced drilling-dynamics tool in a variety of different applications and tool configurations including rotary-steerable systems (RSSs) and steerable-motor BHAs. The bending-moment data can be both transmitted to the surface while drilling and recorded in on-board memory for post-run processing and detailed analysis.