This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188587, “Unlocking Egypt’s Unconventional Potential,” by Amr Zaher, Etienne Loubens, Mohamed Zayed, SPE, Nicholas Gill, SPE, Oneil Sadhu, SPE, and Layla El Hares, SPE, Shell, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.
The Apollonia tight-gas chalk play is located in the Abu Gharadig Basin in the Western Desert of Egypt. This has long been ignored as a gas play in the overburden, while the Jurassic and Cretaceous oil fields deeper in the basin have been explored and developed. However, several structures in the Apollonia are known to contain potentially significant hydrocarbon volumes, although a potential Apollonia full-field development is challenging because of regulated gas prices in the Western Desert and low-productivity formations. This paper discusses the process of developing the first unconventional-gas opportunity in Egypt.
Vertical appraisal wells show that low production rates and low estimated ultimate recoveries (EURs) present a challenge for cost-effective development of tight gas in Apollonia. With the play’s decreasing levels of permeability, long-reach horizontal wells are needed with induced stimulation. The optimized technique of deploying multistage hydraulic-fracture stimulation efficiently has been documented and applied successfully in North America and has potential for success in Apollonia. Shell and Apache created a joint-development proposal to unlock the significant stranded gas in Apollonia. The proposal consisted of a staged development, starting with a three-horizontal-well pilot followed by an optional full-field development.
Apollonia is a homogeneous reservoir; however, it is very tight, and induced stimulation by hydraulic fracturing is required to produce a commercial and sustainable production rate. Smectite and illite contribute to reservoir quality and can be predicated by conventional logs. Fracture densities in Apollonia are low. The fractures are either closed or only partially open, and their contribution to production is perceived to be low. In addition to these factors, development may require drilling many wells (low spacing) with induced stimulation in order to deliver cost-effective production rates. This requires lower well costs than currently exist. While production from the three existing vertical wells continues, EURs from these wells are suboptimal.
Apollonia comprises tight, microporous chalky carbonates that are proved to contain movable hydrocarbons. The formation is subdivided into four members, Apollonia A (top layer) through D (bottom layer). Apollonia A and C are composed of thick massive limestones (chalk) with minor marly and shaley intervals, while Apollonia B and D are dominated by shale. Most of the porous intervals occur within Apollonia A and C. Regional correlations have shown that most of the thickness variations are confined to Apollonia C and, to a lesser extent, D. However, recent seismic interpretation has shown that there are also thickness variations in Apollonia A and B associated with Eocene inversion. The individual porous zones within Apollonia A and, to a lesser extent, C are laterally correlatable over large distances.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188575, “A New Shortcut Work Flow in Flexible Reservoir Modeling: Introducing Structural Features Without Regridding,” by Alejandro Rodríguez Martínez and Stefano Frambati, Total, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.
Current reservoir-modeling work flows are rigid, because modification to the understanding of the underlying structural model often requires a complete regeneration of the reservoir grid, which brings additional costs, delays, and incompatibilities with past calculations. This paper proposes a novel work flow for structural-features modeling that allows the introduction of faults and other structural and nonstructural features to any simulation grid without modification.
The modeling of hydrocarbon reservoirs is a multiscale and multidisciplinary process that usually involves several months for advancement from seismic interpretation to reservoir simulation. One crucial moment in the life of a reservoir model is the creation of its reservoir-simulation grid. This involves the encoding of the so-called structural model (Fig. 1), a set of surfaces representing interfaces between different geological features. A given grid cell can belong only to one side of each of these surfaces, generating geometrical tension on the grid. Once the reservoir simulation grid is created, every aspect of the simulation depends on it.
Several weeks or even months are spent building and quality checking the reservoir-simulation model, which is completely based on the cell division of the space determined by the reservoir grid. Simulations are then run and compared with actual data, when it is available, or used for conceptual design of production methods and structures. Other times, the model already exists and new production data are acquired. These simulations and comparisons sometimes re-veal fundamental flaws in the simulation model, such as the existence of an unseen or underestimated fault that was not included or the need to model differently the flow across a fault because a fault relay was ignored. In such cases, the engineer can decide either to ignore the issue, leaving an inaccurate model in place for the rest of the field’s life but retaining compatibility with previous simulations, or to modify the reservoir properties manually to mimic the missing feature. These manual modifications, however, are extremely costly, and the result is often nongeological and possibly inconsistent with future evolutions of the model.
A final option is for the seismic-interpretation team to add the missing fault to the structural model. This may require many steps, ultimately changing the geometry and number of cells. Expected timelines will be delayed, the budget will grow, and some development decisions will have to wait for the new simulations. Because of this, in future projects, the engineer will take great care to ensure that every trace of a fault is included in the first version of the structural model. That way, transmissibility multipliers can always be set to unity and the faults can be removed de facto from the actual simulation if need be. This strategy, however, creates large, unwieldy models, often with more than 200 faults.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186289, “Coalbed Methane Development in China: Engineering Challenges and Opportunities,” by Hangyu Li, Shell; Hon Chung Lau, National University of Singapore; and Shan Huang, Shell, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.
For more than a decade, coalbed methane (CBM) has been developed commercially in China, but results have not met expectations. For instance, in 2015, annual CBM production in China totaled less than 5 billion m3 (Bcm) and lagged far behind that of the US (35 Bcm) and Australia (18 Bcm). This paper presents a literature review to determine the engineering challenges and opportunities presented by CBM production in China.
China holds the world’s third-largest CBM resources after Russia and Canada. China has multiple basins that contain CBM resources, though the majority of CBM activities are found in the Qinshui and Ordos basins. Together, these two basins contain more than 30% of China’s total CBM resource volume and 93% of discovered geological reserves.
Commercial-scale CBM production in China began in 2004 but did not see a significant increase until 2008. Since then, production has increased approximately threefold but remains significantly lower than that of the US and Australia, as well as the target set by the Chinese government.
China’s lower CBM production is not the result of a smaller development scale compared with those of the US and Australia. In fact, the Qinshui basin alone contains more CBM-producing wells than does the entire state of Queensland. The lower production is, instead, the result of very low single-well gas rates. US and Australian basins have much higher single-well rates than do the Qinshui and Ordos basins. Understanding and identifying additional factors contributing to the unsatisfactory performance of CBM production, however, also is of critical importance.
of the CBM Basins in China Most of China’s CBM development focuses on high-rank (Qinshui) and mid-high-rank (Ordos) coals. It is worth noting that, although there is abundant low-rank coal in the Ordos basin, the large-scale CBM development is found in the eastern part of the basin, where mid- to high-rank coals dominate. The problem with high-rank coals, however, is that they generally have lower permeability than low-rank coals. The highest permeabilities in either the Qinshui or Ordos basins are hardly higher than 10 md, with a large portion less than 0.1 md, while permeabilities in US basins can be 1000 md, with the majority higher than 10 md. Similarly, Australian basins are much more permeable than Chinese basins. The very low coal-seam permeabilities in the Qinshui and Ordos basins suggest that the low single-well gas rate can be attributed largely to low permeability.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186043, “An Integrated Study To Characterize and Model Natural-Fracture Networks of Gas-Condensate Carbonate Reservoirs, Onshore Abu Dhabi,” by Budour Ateeq, Mohamed El Gohary, Khalid Al Ammari, and Rashad Masoud, ADCO; Abdelwahab Noufal, ADNOC; Ghislain de Joussineau and Martin Weber, Beicip Franlab; and Dinesh Agrawal, IFP Middle East Consulting, prepared for the 2017 SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, 8–10 May. The paper has not been peer reviewed.
Natural fractures can have a significant effect on fluid flow by creating permeability anisotropy in hydrocarbon reservoirs. They can also play an undesirable role in reservoir subsidence and compaction during depletion, with important consequences for production strategy. The investigation of these effects motivated a comprehensive integrated fracture study of three reservoirs from a giant gas-condensate field in Abu Dhabi. The main objective was to build 3D fracture models and compute fracture properties of each reservoir, to be used in dynamic simulations.
The studied reservoirs are gas-condensate-bearing in a carbonate field onshore Abu Dhabi. The field has an anticlinal structure and consists of a series of stacked reservoirs, among which three (Reservoirs A, B, and C) were part of this study. For each reservoir, the production comes mainly from the large gas-bearing area above the gas/oil contact, which is surrounded by a thin peripheric oil rim.
The studied field has a long production history; Reservoir A has produced oil and gas for 30 years. Minor fracturing was observed during routine core analyses in the past, but a comprehensive fracture characterization at field scale was never conducted. Because fractures may have a major bearing on production and could play a significant role in rock compaction and collapse during reservoir depletion, an important objective was to ascertain the risk related to the geomechanical stability of these reservoirs because of the presence of natural-fracture networks.
An integrated work flow was applied in order to characterize fracture distribution and flow effect in the reservoirs properly. The work flow consisted of the following key steps:
Static Fracture Characterization
Fracture characterization using the seismic data initiated the work flow and was followed by the interpretation of fractures from borehole images and core data.
Fracture Characterization From 3D Seismic Data. This task was performed to detect the seismic and the subseismic faults and fracture corridors within the three reservoirs. Seismic fracture-facies maps and fracture-index maps were created on the basis of post-stack discontinuity attributes (e.g., curvature, polar dip, and similarity) computed from the inverted seismic cube.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186343, “Review of Coalbed Methane Prospects in Indonesia,” by C. Irawan, D. Nurcahyanto, I.F. Azmy, J.A. Paju, and W.M. Ernata, SKK Migas, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.
In 2005, two companies began studying the potential of seismic operations for the Kutai and South Sumatra basins (Fig. 1). However, the progress of coalbed-methane (CBM) operations has been slow for several reasons. This paper reviews the efforts to exploit CBM resources in Indonesia, the challenges these efforts have faced, and possible solutions that can make operations more efficient and profitable.
Despite the current industry climate, operators in Indonesia continue to pursue CBM production opportunities. The Indonesian government has stipulated in its contracts with these companies that current operations must yield production within a set time frame, highlighting the importance of making such operations cost-effective.
Currently, many methods are avail-able to drill CBM wells. In early efforts to exploit CBM wells, contractors used conventional methods to drill a well at a target depth of 500 to 800 m at a high operational cost, but time frames were not met. Of 51 exploration contract areas involving CBM in Indonesia, only 17% of these have fulfilled their commitment. Obstacles that prevent success in these endeavors are often nontechnical in nature, including organizational difficulties (suboptimal financial conditions of operators), land- and permit-acquisition issues, challenges in community relations, gaps in the supply chain, and problems with access and infrastructure. Standard operating procedures (SOPs) are difficult to formulate and implement under these conditions. The CBM well must follow industry operational standards, which, when com-pared with standards involved in the mining industry, for example, involve a higher level of technology and the need for more permits and, thus, a greater cost.
Indonesia CBM Contract Area Indonesian unconventional prospects are essentially divided into two areas, Sumatra and Kalimantan. These areas contain the most abundant coal-seam prospects. However, proved resources do not equal the estimated resources calculated more than a decade ago.
Geologically, target coal seams in the Sumatra and Kutai basins differ only in their depth. The target coal seams in Sumatra are shallower than those in the Kalimantan region. In both basins, the cost per well is high.
One of the more exciting aspects of artificial lift is the constant influx of new technologies and new ideas that the discipline invites. Inventors appear to be regularly developing “the next new thing” in artificial lift. Some ideas are so brilliant and so obvious, you ask yourself, “Why didn’t I think of that?” Other ideas seem so zany and so ill-conceived, you ask yourself, “What were they thinking?” In every case, these new technologies have the same goal: To produce more oil and gas more reliably and more cost-effectively.
One of my artificial-lift mentors has such a long history of developing and championing new downhole pumping technologies that he once described his career as the “relentless pursuit of the everlasting pump.” Even in retirement, he continues this lifelong passion. Yet, it occurs to me that the everlasting pump may actually exist today—through the correct application of field-proven technology. Although we seem to have a never-ending supply of new artificial-lift technologies, the technologies that consistently allow us to achieve our technical and business goals are usually the old ones. There is a catch, however: You need to apply those technologies correctly.
Applying artificial-lift technology correctly means selecting the right lift method in the first place, selecting the right system components, installing the equipment correctly, performing effective surveillance, and performing root-cause failure analysis so that we can learn from our mistakes and enable continuous improvement. All of this requires a coordinated effort, not just between vendors and operators but also between the various groups within the operating companies themselves. Each of these groups has a stake in the success of the well and should be aligned around a common set of goals to ensure that the artificial-lift system performs reliably and delivers optimal production and does so in a cost-effective manner.
All of the papers selected for this section concern the correct application of field-proven artificial-lift technology. Paper SPE 181216 describes the surveillance methods used by one operator to improve the reliability and performance of their beam pumping systems. Paper SPE 186254 describes a method to deploy electrical submersible pumps in gassy horizontal wells to improve gas handling and mitigate slugging. Paper SPE 186110, written by one of our recent Legends of Artificial Lift inductees, provides new insights into the application of injection-pressure-operated gas-lift valves, to allow operators to improve the design and overall reliability of gas-lift installations.
To see more great artificial-lift papers like these and to welcome our latest class of Legends, I invite you to join us for the 2018 SPE Artificial Lift Conference and Exhibition—Americas on 28–30 August 2018 in The Woodlands, Texas, USA.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 28123 A Step Change in Safety and Quality for ESP Deployment in the North Sea by L. Pastre, Schlumberger, et al.
SPE 190090 Detecting Failures and Optimizing Performance in Artificial Lift Using Machine Learning Models by Mike Pennel, OspreyData, et al.
SPE 187490 A Novel Approach to Distributed Field-Based Gas-Lift Facilities by Siddharth Mullick, Anadarko Petroleum, et al.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190204, “An Integrated CO2 Foam EOR Pilot Program With Combined CCUS in an Onshore Texas Heterogeneous Carbonate Field,” by Z.P. Alcorn, SPE, and S.B. Frederiksen, University of Bergen; M. Sharma, University of Stavanger; A.U. Rognmo, SPE, University of Bergen; T.L. Føyen, SPE, University of Bergen and SINTEF; and M.A. Fernø, SPE, and A. Graue, SPE, University of Bergen, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed.
A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Previous field tests with CO2 foam report varying results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. A more-integrated multiscale methodology was required for project design to further understand the connection between laboratory- and field-scale displacement mechanisms.
East Seminole Field
The East Seminole Field in the Permian Basin of West Texas was discovered in the early 1940s with an estimated 38 million barrels of original oil in place (OOIP). The field was developed throughout the 1960s, producing 12% OOIP through pressure depletion. Water floods began in the early 1970s and continued into the 1980s with strategic infill drilling, reducing the well spacing from 40 to 20 acres.
Tertiary CO2 floods began in inverted 40-acre, five-spot patterns in 2013 in the eastern portion of the field. Miscible CO2 injection initially increased oil production and reservoir pressure. However, rapid CO2 breakthrough, high producing gas/oil ratio (GOR), and CO2 channeling was soon observed in peripheral production wells. CO2 performance suffers because of reservoir heterogeneity and unfavorable mobility ratios between injected CO2 and reservoir fluids, resulting in poor areal sweep efficiency, high producing GOR, and CO2 channeling.
As seen in other areas of the Permian Basin, tilted fluid contacts, presumably resulting from basin activity or a breach of seal, have created a deeper residual oil zone (ROZ). These zones are thought to have been naturally waterflooded through hydrodynamic dis-placement and have been shown to contain considerable immobile oil (20 to 40% OOIP) that can be mobilized by CO2 flood. Thus, the residual oil saturation in the ROZ is similar to waterflooded zones and establishes it as an economically attractive target for tertiary CO2 recovery efforts.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186254, “Improve Production in Unconventional Oil Wells Using Artificial-Sump-Pumping System,” by Reda Elmahbes, Regulo Quintero, and Agnetha Evelyta, Baker Hughes, a GE Company, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.
Unconventional oil wells present challenges to electrical-submersible-pump (ESP) systems and can limit production potential. An artificial-sump-pumping system used in unconventional oil wells with steep decline curves and high amounts of free gas has been shown to operate reliably and economically. This paper presents a comparison of conventional ESP methods and artificial-sump systems for which free gas and gas slugs are a challenge.
Unconventional oil wells usually have inadequate reservoir permeability. To enable a significant amount of fluid flow from the reservoir to the wellbore, the wells are drilled horizontally and multistage hydraulic fracturing is performed to expose as much reservoir to the wellbore as possible.
The long horizontal laterals create unique production challenges. As the reservoir pressure declines in unconventional reservoirs, gas is released from the fluid and accumulates in hump undulations of the horizontal section. When the gas slugs break free, they create cycling and gas locking that has a negative effect on system performance and reliability. Repeated shutdowns because of gas locking have a negative effect on the production and longevity of the artificial-lift system. Reducing the running time for an artificial-lift system can significantly increase operator capital and operational expenses (OPEX).
Some gas slugs can be very large and can create a low-flow or no-flow condition that is challenging for most artificial-lift systems. Therefore, gas slugs must be separated from the liquid before entering the downhole pump to improve production and enhance artificial-lift-system reliability. Designing a system that can avoid slugs and prevent excessive amounts of gas from entering the downhole pumping system is crucial to produce economically from unconventional oil wells.
An artificial-sump-pumping system is a new form of gas mitigation that uses an ESP artificial-lift method with an inverted shroud that surrounds the entire system. The ESP is equipped with a recirculation system to keep the ESP motor cool during slugs. In addition, the fully encapsulated system has enhanced motor-lead-extension (MLE) protection that helps avoid cable damage during run in hole (RIH), especially for 5½-in.-casing applications. This solution is mainly used for wells that are very gassy and have the potential for gas slugs.
Fig. 1 shows a schematic for an artificial sump with a recirculation system.
Optional components are recommended to be used on the basis of well conditions and fluid characteristics. For instance, a sand-control system is recommended for applications where sand and abrasive risk is high.
Recently, a lot of discussion has revolved around the benefits of multilaterals in unconventional reservoirs. But is this truly the next breakthrough for the industry, or is it all hype?
No doubt enormous need exists for a technology such as this to improve reservoir recovery and reduce well cost.
The current modus operandi in many plays is to drill horizontal hydraulically fractured wells. The results, however, continue to show that these well types are not effective at draining the reservoir. This is a result of complex hydraulic-fracture geometries with very short propped heights and lengths. Fracture complexity is a natural phenomenon now proved by coring and is likely caused by reservoir stratigraphy and geomechanics. Completion engineers typically counteract this, to some degree, by pumping more fracture treatments in the horizontals. This ineffective drainage points to the benefits of greater reservoir contact with a multilateral.
As well as improved drainage, multilateral technology also can reduce well cost by avoiding the necessity to drill top hole for the second (or third) lateral and requiring only one completion and one set of surface equipment.
Multilateral technology has been around for many years; however, what has changed in recent times is the reliability of these systems, with more than 98% reliability quoted in a recent publication. Hydraulically fracturing the laterals is now possible as well.
Companies such as Occidental, BP, and ConocoPhillips are evaluating the potential of this technology in onshore unconventional plays. In fact, in the fourth quarter of 2017, Occidental successfully performed its first pilot.
Enormous need for this technology exists, and time will tell whether it is the next major step in subsurface technology to improve the unit cost of production.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 188231 Modeling Early-Time Rate Decline in Unconventional Reservoirs Using Machine Learning Techniques by Aditya Vyas, Texas A&M University, et al.
SPE 186107 Optimization of Spacing and Penetration Ratio for Infinite-Conductivity Fractures in Unconventional Reservoirs: A Section-Based Approach by S. Liu, Texas A&M University, et al.
SPE 186092 Rate Dependence of Bilinear Flow in Unconventional Gas Reservoirs by M.S. Kanfar, University of Calgary, et al.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181216, “Proactive Rod-Pump Optimization: Leveraging Big Data To Accelerate and Improve Operations,” by Tyler Palmer, SPE, and Mark Turland, SPE, Denbury Resources, prepared for the 2016 SPE North American Artificial Lift Conference and Exhibition, The Woodlands, Texas, USA, 25–27 October. The paper has not been peer reviewed.
This paper presents how a US onshore operator took a three-step approach to optimize more than 100 rod-pump wells. The approach involved data consolidation, automated work flows, and interactive data visualization. This approach led to increased unit run times, decreased unit cycling, improved production and equipment surveillance, and increased staff productivity. The ultimate goal was to increase profitability by decreasing lifting costs and increasing operating efficiency.
The processes and tools described in this paper cover a subset of approximately 125 wells in eastern Montana and western North Dakota, but they have been designed to be applicable and scalable to any fields that use rod-pump artificial-lift systems with supervisory control and data acquisition (SCADA). Simple modifications can be made to the tools and processes for wells that do not have SCADA capabilities.
While optimization efforts and best practices have been implemented for the subject rod-pump systems during the past 6 decades, many opportunities remain to create additional value. Empirical knowledge from field personnel serves as the basis for the analytical model. Categorizing and quantifying the observations made by the field personnel is critical to developing any analytical model involving oil and gas operations. On the basis of feedback from field personnel and engineers, the following areas had the most potential for improvement: data consolidation, automated work flows, and data visualization.
The data-consolidation issue stems from data being located in multiple file locations, sometimes being stored in nontabular formats and initially lacking the necessary unique identifiers for mapping between databases. Automated work flows were essentially non-existent; wells were analyzed individually using deterministic, static data. Data were previously visualized in multiple locations but never integrated into a single, interactive visualization tool.
The opportunities to maximize asset value led to the development and implementation of the rod-pump optimization tool (RPOT). The RPOT is a data-visualization tool that generates a single recommended optimization action (ROA) for each well being analyzed. The ROA logic calculates the optimal amount of fluid for a well to produce on the basis of its inflow, while accounting for surface and subsurface equipment constraints.
General examples of ROAs include slowing wells down by making a specific sheave adjustment, speeding wells up by a specified strokes/minute (spm) amount, upsizing the downhole pump to a specific pump size, or upsizing or converting to a different artificial-lift system. If in accurate or incomplete data are brought into the database, the ROA specifies the data source that needs to be quality-checked.