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 The paper has not been peer reviewed.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 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 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.
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.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186110, “Effect of R Ratio on Performance of Injection-Pressure-Operated Gas-Lift Valves,” by K.L. Decker, SPE, Decker Technology. The paper has been peer reviewed and published in the February 2018 SPE Production & Operations journal.
An injection-pressure-operated gas-lift valve’s closing force comes from a nitrogen charge acting on the effective area of the bellows (Ab) or a spring force. The opening force is the production pressure acting on the area of the port (AP) plus the injection pressure acting on the bellows effective area minus the area of the port. The ratio AP / Ab is referred to as the R ratio, which traditionally has been considered constant for every valve of the same type. The actual R ratio, however, is not a constant. This paper describes the consequences of using an assumed R ratio in a gas-lift design that is not the same as the actual R ratio of the valve.
The force from a spring or a nitrogen-charged dome acting on the effective area of the bellows creates a contact area be-tween the ball and port. When using a square-edge seat, this contact area is de-fined by an outer seal diameter and the port diameter. The contact area is an annular ring on the surface of the port where neither production nor annulus pressure is acting. The width of this area changes with the valve-dome pressure, strength of port material, port size, and lap band. Fig. 1 shows a typical nitrogen-charged gas-lift valve.
For chamfered ports, the ball makes contact on the chamfered surface. In this case, an outer sealing area and an inner sealing area exist because of the lap band. The outer diameter of the lap band defines the annulus-pressure sealing area. The inner diameter of the lap band defines the production-pressure sealing area.
The R ratio can be obtained by an equation that uses properties of the valve (please see the complete paper for the equation). It generally is not possible to measure the seal area or the lap-band width directly; therefore, the R ratio determined by means of the equation should be considered an estimate.
The most reliable and accurate method of determining the R ratio is by means of pressure testing. Both opening- and closing-pressure tests must be performed. Please see the complete paper for the equation to calculate R ratio using the opening and closing pressures.
The opening pressure is commonly used as the basis for preparing a valve for service in a well. The reason is the ease with which it can be tested and the idea that the valve acts as a backpressure regulator. The gas-lift technician strives to keep the opening pressure within ±5 psi of what is requested. The dome pressure is normally charged to a pressure slightly higher than intended. The opening pressure is adjusted by lightly tapping the core valve of the nitrogen dome, releasing a small amount of nitrogen until the desired pressure is achieved. The practical ability of adjusting a very high pressure to an accuracy of ±5 psi by the tap of a hammer on the core valve is generally not within the skill set of gas-lift technicians.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188594, “Saturation Modeling Under Complex Fluid-Fill History—Drainage and Imbibition,” by H. Xian, SPE, L. Beugelsdijk, SPE, and A. Kohli, SPE, Shell; E. Fokkema, SPE, Nederlandse Aardolie Maatschappij; and A. Cense, Shell, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.
This paper presents a saturation-modeling approach for fields and reservoirs with complex hydrocarbon-charging histories. The model resolves saturation-height functions for the primary-drainage, imbibition, and secondary-drainage equilibriums. As part of the approach, a method of evaluating the residual-hydrocarbon saturation below the initial free-water level (FWL) is proposed. The developed theory is based on the principle of capillary-pressure/saturation hysteresis on the drainage/imbibition process in a water-wet system.
Many discovered oil and gas fields are found to have gone through complex fluid-fill histories where residual hydrocarbons are observed below the FWL. To add to the complexity, some of these are giant fields and are divided into compartments with varying contacts and FWLs.
To model saturation-height dependencies for reservoirs in fields under imbibition equilibrium, one of the adopted practices is to use a drainage model built from core data or log data to compute the saturation starting from the original FWL contact but only calculate the hydrocarbon-in-place volumes above the initial FWL. Another common practice is to build log-based drainage models using the current FWL while ignoring the uncertainties in the transition zone from the imbibition effect. These approaches typically lead to an inappropriate estimation of the hydrocarbon saturation in the transition zone and normally require separate models for different segments of the field.
In this paper, an approach is presented for modeling the core capillary-pressure imbibition and secondary drainage cycles, integrating with log-based saturation-height models, and designing a work flow for upscaling and implementation in 3D reservoir models.
Imbibition and Secondary-Drainage-Model Theory
Hysteresis of Saturation/Capillary Pressure and Analytical Imbibition Model Method. Modeling of saturation/capillary pressure of primary-drainage-imbibition hysteresis is more complicated than other types of hysteresis effects because its cycle is not a closed loop; the imbibition route does not end at the starting point of the primary drainage route. Fig. 1 shows the multi cycle drainage/imbibition scanning curves in mixed-wet or strongly water-wet rock systems. Saturation changes caused by the imbibition-hysteresis effect are larger at lower capillary pressures in the transition zone but become insignificant over the higher capillary pressures across the main nonwetting-phase column.
The primary-drainage capillary pressure can be measured by high-pressure mercury injection, porous plate, and centrifuge. Spontaneous imbibition can be measured only by use of the porous-plate technique or by use of an Amott cell. The forced imbibition part of the imbibition capillary pressure can be measured by porous plate and centrifuge.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 28080, “Monitoring Flexible Risers With Optical Sensors—Operational Experience and Future Perspectives,” by B.M. Santiago, S.R. Morikawa, W. Carrara, A. Kravetz, and J.A. Martins, Petrobras, prepared for the 2017 Offshore Technology Conference Brasil, Rio de Janeiro, 24–26 October. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
The integrity management of flexible pipes used in subsea production plays a major role in maximizing the availability of the production systems while minimizing safety and environmental risks. One of the key areas for integrity management is the riser top section, where high tensions and curvatures result in high stresses and may lead to fatigue issues. A monitoring technique known as Monitoring Based on Optical Fiber Attached Directly on Armor Wires, or MODA, has been developed to assess the integrity of the tensile armor at the top section of flexible risers.
A flexible pipe is composed of several layers, each having a specific function (Fig. 1). The carcass is a metallic layer designed to withstand external compression forces in the radial direction. The internal pressure sheath is a polymeric layer used to contain the fluid inside the pipe. The pressure armor is a metallic layer designed to withstand the internal pressure. The tensile armors are made of metallic wires designed to resist axial forces acting on the pipe. In risers, the tensile armors are responsible for keeping the flexible pipe suspended from the floating production unit (FPU). The outer sheath wraps the other layers, protecting them from the external environment. The region inside the internal pressure sheath is called the bore, and the region between the pressure barrier and the outer sheath is known as the annulus space.
The riser top section is subjected to high tensions because of the weight of the riser and to cyclic tensions and curvatures because of FPU movement, which results in high constant stresses and significant cyclic stresses in the tensile armors. This combination may lead to fatigue issues, especially in a flooded-annulus condition, which severely hinders the pipe capacity to withstand cyclic loads.
The MODA monitoring technology has been developed to better assess the integrity of the tensile armor at the top section of flexible risers.
MODA Development History. At its beginning, the MODA concept was only retrofitted to risers already in service. To install the MODA sensors, it was necessary to remove a portion of the outer sheath, attach the optic-fiber sensors to the wires, repair the outer sheath, and then provide an optical path to an equipment room at the FPU where the MODA equipment was to be installed. Substantial resources were needed in each MODA installation, and only the most critical risers were considered for monitoring.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE/IADC 184739, “Future Workforce Education Through Big-Data Analysis for Drilling Optimization,” by Y. Zhou, SPE, T. Baumgartner, G. Saini, SPE, P. Ashok, SPE, and E. van Oort, SPE, The University of Texas at Austin; M.R. Isbell, SPE, Hess Corporation; and D.K. Trichel, formerly of Hess Corporation, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, The Netherlands, 14–16 March. The paper has not been peer reviewed.
An operator partnered with the drilling-automation research group at The University of Texas at Austin to develop a work flow for big-data analysis and visualization. The objectives were to maximize the value derived from data, establish an analysis toolkit, and train students on data analytics. The operator provided data sets, business and technical objectives, and guidance for the project, while a multidisciplinary group of undergraduate and graduate students piloted an analysis work flow.
The project stakeholders agreed on three main objectives. The foremost objective was to maximize the value from the tens of gigabytes of data gathered during drilling operations. Several work streams were selected to help identify key drilling-performance limiters and cost-saving opportunities. These work streams include assessment of the bottomhole-assembly (BHA) and directional-drilling performance by using measures such as wellbore tortuosity and time-based vibration data to create meaningful visualizations and implement standardized data structures.
The second objective was to establish a standardized data-analysis toolkit. The steps toward such a toolkit were to identify, streamline, and document the working process to establish work flows and to build software tools that automate these work flows (e.g., perform analysis or visualization of the data).
The third objective was to help educate undergraduate students and equip them with the skills necessary to tackle problem in a big-data world.
The data available for this project covered four pads in the Bakken Formation comprising 16 wells that were drilled from 2014 to 2015 for a total of 256 active rig days. The data were the product of a drilling-automation pilot project previously published by the operator. The data set for each well was comprehensive and included well-planning reports, geology information, surface-sensor data, directional surveys, daily drilling reports (DDRs), and extensive measurement-/logging-while-drilling and other downhole data.
Three main deliverables formed the basis for the data-analysis toolkit (Fig. 1).
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27663, “Stones Development: Turritella FPSO—Design and Fabrication of the World’s Deepest Producing Unit,” by Blake Moore, Andrew Easton, Jonathan Cabrera, and Carl Webb, Shell International Exploration and Production, and Babu George, SBM Offshore, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
The Stones Project is in the emerging Lower Tertiary trend in the Gulf of Mexico ultradeep water. A floating production, storage, and offloading (FPSO) unit was selected for the floating production system to address the stepwise development of the Stones Field. The Turritella FPSO (Fig. 1) is the deepest floating production system in the world and presented many challenges to successful execution of the surface host facilities.
The Stones development is along the Walker Ridge protraction area in the deepwater Gulf of Mexico, in water depths ranging from 7,500 to 9,500 ft. The field was developed using a disconnectable FPSO tied to a subsea development. Nominal production capacities will be 60,000 B/D of fluids, 30,000 B/D of produced water, and 15 MMscf/D of associated gas. The FPSO design was based on the conversion of an existing Suezmax-scale, double-hull tanker.
Key design decisions during front-end engineering and design (FEED) and pre-FEED in 2012 and 2011 established many of the key design criteria that guided the design of the FPSO.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 185283, “Leveraging CLD Potentials: Optimizing Economics Through Dynamic Well Control,” by Robert Ziegler, SPE, Weatherford International, and Evelyn Baldwin, SPE, Maersk Training, prepared for the 2017 SPE/IADC Managed Pressure Drilling/Underbalanced Operations Conference and Exhibition, Rio de Janeiro, 28–29 March. The paper has not been peer reviewed.
Maximizing the potential of closed-loop drilling (CLD) to achieve dynamic well control and effectively cut costs is an often overlooked opportunity in times of low oil prices. This paper details the operational effects of CLD to demonstrate its ability to yield operational-process-safety improvements and cost savings over conventional methods. While managed-pressure drilling (MPD) often is the tool that finally enables operators to reach their objectives, major cost savings come when MPD is integrated in the well-planning process from the beginning.
MPD for CLD
Not too long ago, the topdrive was in a similar position on the technology-adoption curve as MPD is today. The industry was in a downturn at that time, too—oil prices were low, cost pressure was high, and horizontal drilling had just taken off. The topdrive rental business was booming, and, the moment the directional phase of a well was reached, the topdrive was mobilized. Drillers soon started to like the additional abilities the topdrive gave them, such as reducing nonproductive time (NPT) and mitigating stuck-pipe events. Even in the cost-sensitive land market, the topdrive is now considered standard equipment, as it has been offshore for quite a while.
For MPD equipment, the situation is reversed. While the land market in the US has adopted the rotating control device as standard equipment, offshore in the Gulf of Mexico, where many of the most challenging wells are being drilled, adoption of the technology has been slow.
In other areas of the world, however, MPD adoption is moving quicker. Most notably, in loss-prone carbonates of Southeast Asia; in the subsalt environment of Brazil; and, to a certain extent, in Angola, MPD from floaters has been more widespread.
The experience from land wells can be transferred safely to offshore surface-blowout-preventer (BOP) operations (e.g., on jackup rigs, tension-leg platforms, tender-assisted drilling, and other platform rigs). The advantage offshore is that the rig moves are much simpler than for land operations, so complex piping for full MPD operations can remain in place.