bluuebunny/crossref_metadata_2025_split huggingface dataset:
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 The paper has not been peer reviewed.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.