bluuebunny/crossref_metadata_2025_split huggingface dataset:
Upfront Reservoir Monitoring Investment Promises Long-Term Rewards
Authors: Bostick Tad 
Published: February 2015

Guest Editorial
The industry’s continued migration into deeper, hotter, and more unconventional oil and gas reservoirs carries the potential for significant financial rewards and major economic risks. Because the development of unconventional reservoirs often requires some form of stimulation—thermal stimulation for heavy oil formations and hydraulic fracturing for shale plays—well construction costs are reaching new highs. Rather than developing these wells in a trial-and-error or even blind fashion, more operators realize that the only way to maximize the value of these assets is through real-time monitoring at the reservoir level.
Permanent reservoir monitoring calls for the deployment of one or more downhole sensors to monitor and record a number of reservoir properties, such as temperature, pressure, and flow rates at various locations in and around the wellbore. By monitoring these properties in real time and over time, operators can gauge the progress of reservoir development at each stage of the well’s life cycle.
Full-Asset Life Cycle Benefits
During fracture stimulation of shale wells, for example, a permanent monitoring solution can reliably report information on the fracture network being created, including data on both the quantity and quality of fractures being created in different zones. In steam-assisted gravity drainage (SAGD) wells, downhole temperature sensors can track the propagation of steam moving into the formation, and then the progress of heated oil moving into the producing well.
Once the well is brought onto production, these same monitoring tools can accurately measure the pressures, temperatures, and flow rates of fluids at different points in the wellbore and from different producing zones. Such insight informs when the operator may need to implement some form of remediation or artificial lift in the well to boost dwindling production rates. Once artificial lift has begun, the real-time reservoir data can help optimize the pumping rates of various lift technologies to maintain production at desired rates.
The benefits of permanent reservoir monitoring extend past a single well to encompass production optimization at a field level. For example, by installing permanent sensors in producing, injection, and monitor wells as part of an enhanced oil recovery (EOR) campaign, the operator can feed these data into simulation models to track production across the reservoir. Such information can then be used to aid development decisions—an expansion of EOR or the drilling of additional wells—to boost the long-term production of an entire field.
Weighing Monitoring Options
The past 2 decades have brought an impressive pace of development for different permanent downhole monitoring options. For operators, the choice of a system is a function of several interrelated factors.
Technology Update: Managed-Pressure Drilling Advances Expand Options of Onshore Drillers
Authors: Hannegan Don 
Published: February 2015

Technology Update
This is an update on several managed-pressure drilling (MPD) technologies and downhole drilling performance-enhancing tools in use onshore and is the first of a two-part series. The second article on offshore MPD technologies will appear in the February issue of JPT.
Numerous recent advances in managed-pressure drilling (MPD) technology have led to the increased use of MPD and an expanded repertoire of solutions for a variety of drilling challenges.
This article will focus on several such advances in onshore drilling, including new rotating control devices (RCDs), additional MPD applications, new downhole tools activated by radio frequency identification (RFID), and a rate-of-turn gyroscope, which is based on a microelectromechanical system (MEMS) and uses smart algorithms to alert drillers when harmful rotational dynamics are occurring in the drillstring.
Conventional Systems vs. MPD
The hydraulics of conventional drilling was founded in the Spindletop field in Beaumont, Texas, circa 1901. After the initial gushers, the celebration of such quickly waned, and the industry learned to drill with a weighted fluid—literally mud from a cattle pond at the time—to enable drilling into the reservoir without inviting a blowout. The rig pumps returned mud and cuttings to an open-to- atmosphere drilling nipple beneath the rig floor.
Thus, the hydrostatic head pressure of the annulus returns column became the primary well-control barrier. A precipitous fall of the returns compromises that barrier and an overflow signals a potential well-control situation.
For more than a century, this system has served the land drilling industry well. However, most of the “easy” prospects that can be drilled that way have already been drilled. An inherent weakness of the system has become more troublesome, and a growing number of otherwise promising prospects have proved undrillable with the conventional approach. The only way to adjust the pressure on the exposed formation without interrupting drilling is to change the circulating rate, which slightly increases or decreases the equivalent mud weight (EMW).
The closed-loop system of MPD adds an important component to the equation, enabling more precise management of the wellbore pressure profile, whether circulating or not. EMW may be managed with mud pumps on the front side or with discrete applications of backpressure on the back side. Specialized enabling tools include a fitfor- purpose RCD, nonreturn valves in the drillstring, and a dedicated drilling choke manifold. The choke may be manual, semiautomatic (a typical hydraulic or more precise electric set-point choke) or automatic (controlled by programmable logic). EMW complements the primary well-control barrier.
Tengiz Field Sector Model for IOR/EOR Process Evaluation
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 170605, ’A Sector Model for IOR/EOR Process Evaluation,’ by Shie-Way Wang, Batima Yeskaiyr, SPE, and Chuck Walker, Tengizchevroil, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27-29 October. The paper has not been peer reviewed.
This work presents a methodology to construct a sector model for the Tengiz field that covers one-sixth of the field area to evaluate improved-/ enhanced-oil-recovery (IOR/EOR) processes to increase oil recovery through the life of the field. The method takes into account boundary flux, edge wells, and compositional effects to replicate full-field-model performance and subsequently generate alternative predictions. This model matches production/injection data of existing wells and the anticipated performance of future wells in the full-field model.
Introduction
The Tengiz field is a giant carbonate oil field onshore western Kazakhstan at the northern end of the Caspian Sea’s eastern shoreline. Tengiz is a stratigraphic trap consisting of a carbonate buildup with a large central platform area (10×15 km) with a raised rim area (up to 2 km wide). The Tengiz reservoir has mesa-like geometry overall—flat topped and steep sided. The top of the platform has a slight regional tilt (less than 1° to the south). The sides of the platform generally dip approximately 25° on all flanks.
Production has been mainly from primary pressure depletion through oil expansion. Sour-gas injection was implemented in 2007 to address pressure decline and improve recovery efficiency. In general, the platform lacks fractures and is best suited for gas injection, whereas the slope is suitable for depletion drive because of high fracture density. Because gas injection is limited to the platform region, the main objective of this study is to investigate the best pressure-maintenance or IOR/EOR method to apply to the fractured slope region.
Sector Model
The area of the field modeled with the sector model was selected to include geological regions, material-balance regions, and displacement processes that are representative of Tengiz as a whole. The model incorporates 15.2% of the field surface area and has platform and slope regions within its boundary. Fig. 1 shows that the sector model includes (a) two five-spot existing sour-gas-injection patterns (green-line-pattern area) and (b) seven future-growth-project and sour-gas-injection patterns in the central platform region (black-line-pattern area). This sector model has 127 wells divided into two groups. The first group has 62 future and existing producers and eight injectors associated with base business operations. The second group has 57 potential future infill wells for long-term IOR/EOR development plans.
CO2 Low-Salinity Water Alternating Gas: A Promising New Approach for EOR
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169071, ’CO2 Low-Salinity Water Alternating Gas: A New Promising Approach for Enhanced Oil Recovery,’ by Cuong T.Q. Dang, SPE, University of Calgary; Long X. Nghiem, SPE, Computer Modelling Group; Zhangxin Chen and Ngoc T.B. Nguyen, SPE, University of Calgary; and Quoc P. Nguyen, SPE, The University of Texas at Austin, prepared for the 2014 SPE Improved Oil Recovery Symposium, Tulsa, 12-16 April. The paper has not been peer reviewed.
Significant advantages have been seen from combining low-salinity waterflooding (LSW) with other enhanced-oil-recovery (EOR) techniques. This paper proposes a novel concept of low-salinity-water-alternating- gas (LSWAG) injection with CO2 under CO2-miscible-displacement conditions. While LSW is an emerging EOR method based on alteration of wettability from oil-wet to water-wet conditions, water-alternating-gas (WAG) injection is a proven method for improving gas-flooding performance by controlling gas mobility. Therefore, LSWAG injection promotes a synergy of the mechanisms underlying these methods that enhances oil recovery further.
Introduction
LSW is receiving increasing attention in the oil industry and is currently identified as an important EOR technique because it shows more advantages than conventional chemical EOR methods in terms of chemical costs, environmental impact, and field process implementation.
Although the benefits of LSW have been realized, the mechanism for incremental oil recovery by LSW is still a topic that is open for discussion. Among the proposed hypotheses, wettability alteration toward increased water-wetness during LSW is accepted widely as the cause for the EOR. It has been found experimentally that low-salinity brine has a significant effect on the shape and the endpoints of the relative permeability curves, resulting in a lower water relative permeability and higher oil relative permeability. The mechanisms of wettability alteration because of ion exchange and geochemical reactions have been implemented successfully in a compositional simulator for modeling LSW. Excellent agreements between simulation results and important measurements from coreflood experiments and pilot observations were obtained with this modeling approach.
Technology Focus: Mature Fields and Well Revitalization (January 2015)
Authors: Lee Jesse 
Published: February 2015

Technology Focus
In last year’s editorial for mature fields, I talked about achieving sustainable growth by employing a combination of new technology and improved production methodology. It is always exciting to see that there are continuous advances on both fronts; however, I would like to take this opportunity to draw your attention to safety (risk to personnel and environment) while the industry is implementing these new ideas. It is not only logical but also prudent to balance safety and project economics, especially while dealing with aging infrastructures. That is, safety should not be considered a cost element. When implemented properly, it is a positive contributor to the economic life cycle.
One of the key aspects of safety in mature fields is to maintain well integrity, which is associated directly with maximizing well productivity and minimizing risks to personnel and environment. It is essential for the operators to construct, implement, and follow through with their own version of well-integrity surveillance and maintenance programs. The value of such programs goes beyond detecting problems early to avoid costly remedial treatments, because the lesson learned can become tremendously useful in the development of game-changing technology. For instance, the industry most certainly will benefit from having a zonal-isolation technology that is superior to what is available today. It is also evident that environmentally friendly chemistry is another way to improve safety.
Speaking of game changing, I am sure most JPT readers have become more productive since the introduction of smartphones and tablets. That is how technology advances fundamentally change the way we live and work. Our industry has embraced the digital age, and the footprint can be seen in many different aspects of producing from mature fields. The integration of digital inventions into the suites of existing technology presents an additional resource for the industry to improve safety and well integrity further in terms of optimizing the production from mature fields.
In this editorial, I have written about safety, well integrity, and digital technology. Therefore, I have selected several papers on these topics to share with you. For 2015, I wish all readers a safe and productive year. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 167424 Real-Time Optimization of a Maturing North Sea Gas Asset With Production Constraints by Ruud van der Linden, TNO, et al.
SPE 167023 Post-Shutdown Recovery Behavior of Horizontal Coalbed-Methane Wells in the Bowen Basin by Tonna Gilbert, Arrow Energy, et al.
SPE 171568 Hyperbolic Decline Parameters During and After Linear Flow: Field Example From the Barnett Shale Using Public Data by H. Pratikno, ConocoPhillips, et al.
Effective Well-Integrity Management in a Mature Sour-Oil Field
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16767, ’Effective Well-Integrity Management in a Mature Sour-Oil Field,’ by Abdulaziz A. Al-Mukhaitah and Surajit Haldar, SPE, Saudi Aramco, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Reproduced by permission.
A large mature onshore Saudi Arabian oil field is producing sour crude oil that multiplies well-integrity challenges. A stringent well-integrity-surveillance and maintenance program is followed for this field. Under this program, any well-integrity-related problem can be predicted through a structured preventive-diagnosis and maintenance schedule for both wellhead and downhole integrity.
Introduction
The Ghawar oil field has moderate-to-high hydrogen sulfide (H2S) and carbon dioxide (CO2) content that is dissolved in crude oil, which demands a very stringent well-integrity program. The well-integrity-surveillance program is a mechanism that is applied to the wells in this onshore oil field to ensure the quality and soundness of all completion components. The developed program not only ensures the identification of well problems at a very early stage but also maintains the soundness and upkeep of all the assets in the field. Data obtained from the monitoring program are used for integrity evaluation that in turn leads to deciding the type of well work required for integrity control and repair and when to perform it. The majority of the well work is cost-intensive, and a sound integrity evaluation is key to its success.
The Program Approach
In small fields, manual tracking and monitoring of well-integrity-related issues are reasonable, but in large oil fields this approach can invite human errors. Automation of this important activity can reduce human errors, and a systematic process is established that can enhance the efficiency of tracking the problematic wells with a definite action plan to fix the issues in a timely manner. The well-integrity- monitoring program starts with the following six primary well-integrity inspections or surveys, carried out periodically for each well:
Integrity testing and maintenance (greasing) of wellhead valves
System-functionality and -integrity testing for surface and subsurface safety valves (SSVs and SSSVs, respectively) and emergency-shutdown (ESD) systems
Annuli pressure and sample survey
Landing-base inspection
Downhole-temperature-profile survey
Corrosion logging
The well-surveillance program has a manifold approach that consists of the following steps:
Maintain a survey-frequency-tracking system.
Analyze, validate, and approve the primary surveys to identify problem wells.
Maintain a problem-well-tracking system.
Repair the problems through minor maintenance; if this is not possible, tag the well for workover operations.
Digital Core Analysis and Pore-Network Modeling in a Mature-Field Project
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24772, ’Application of Digital Core Analysis and Pore-Network Modeling on the Basis of 3D Micro-CT Images for an Enhanced-Oil-Recovery Project in a Mature Oil Field in East Malaysia,’ by W. Nur Safawati, Bt. W.M. Zainudin, Zahidah M. Zain, and Lutz Riepe, Petronas, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed. Reproduced by permission.
For the planning of an enhanced-oil- recovery (EOR) project in a major mature oil field in east Malaysia, an extensive routine-core-analysis (RCA) and special-core-analysis (SCAL) program has been performed on unconsolidated clastic reservoir rocks. In view of the limited availability of homogeneous core plugs of suitable size for coreflooding experiments and for “conventional” SCAL laboratory investigations, a complementary analysis of petrophysical properties was performed on the basis of the acquisition of high-resolution 3D microcomputed-tomography (MCT) images.
Introduction
As part of an extensive core study for this field, the “conventional” core-analysis program was complemented by acquiring 3D images and applying digital-core-analysis (DCA) and pore-network- modeling (PNM) methods at different scales with the following main objectives:
Visualize the status and monitor potential changes of pore morphology, fluid distributions, and wettability during the handling and execution of laboratory experiments on unconsolidated-friable-rock samples.
Evaluate and model the impact of sample heterogeneity and wettability changes on petrophysical properties.
Provide petrophysical properties for individual distinct rock types at pore scale for heterogeneous or irregularly shaped samples that are not suitable or available for RCA/SCAL and flooding experiments.
Scale up drainage and imbibition predictions of subplugs from heterolithic/laminated plugs to full-plug scale and, potentially, further to reservoir scale.
However, because of the lack of preserved core material from earlier wells, and the relatively poor recovery of new conventional cores from recent infill wells in this field, alternative data-acquisition options were investigated in this pilot test on the basis of the significant improvements in, and encouraging results from, DCA and PNM technologies in recent years.
Procedures
Sample Selection. Approximately 22 m of core was recovered from the shallower reservoir sections of two wells (three cores from Well A from a depth interval between 700 and 800 m and three cores from Well B from a depth interval between 1100 and 1300 m), but only 8 m was suitable for plugging. The low-resolution medical computed-tomography images from the whole core indicated a high extent of rubble and broken and highly fractured unconsolidated sections.
Abandonment of Subsea Wells in the Jabiru and Challis Fields
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170523, ’Abandonment of 19 Subsea Wells in the Jabiru and Challis Fields,’ by Iain Clyne and Neil Jackson, PTTEP, prepared for the 2014 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, 25-27 August. The paper has not been peer reviewed.
This paper describes the preplanning and execution of Australia’s largest subsea well-abandonment campaign to date. The Jabiru and Challis fields are located in the Timor Sea, 640 km from Darwin, Australia. The fields consist of 13 subsea producers and six suspended or partially abandoned wells. The paper describes actual experience in a relatively uncommon operation in the industry and includes learnings that can be applied to future development planning.
Introduction
The Jabiru field was discovered in July 1983, with a total of 17 wells drilled to appraise and develop the structure. The field was developed with five subsea production wells tied back to a floating production, storage, and offtake (FPSO) facility. Water depth is approximately 120 m. In addition to the five subsea producers, there were three suspended or partially abandoned wells in the field.
The Challis and Cassini fields were discovered in October 1984 and June 1988, respectively. Cassini is a single-well satellite field, but for the purposes of this paper has been classified as part of the Challis field. In total, 18 wells were drilled to appraise and develop the structure. Production commenced in December 1989 and ceased in September 2010. The field was developed with eight subsea production wells tied back to an FPSO facility. Water depth is approximately 110 m. In addition to the eight subsea producers, there were three suspended or partially abandoned wells in the field.
It was originally intended to carry out the entire abandonment in one continuous program. However, time pressures required two phases. The four simplest wells were moved forward into a Phase 1 program and carried out at the beginning of the rig campaign. The remaining wells were abandoned in Phase 2 following the drilling of three exploration wells. A semisubmersible rig was deemed best for the project.
Preplanning
There were four wells that were already abandoned subsurface to the extent that only wellhead removal was required. To assist in planning, the remaining wells that all required re-entry and subsurface abandonment were divided into abandonment types.