This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190062, “A Pulsed-Neutron Comparison Between an Open- and Casedhole Well: An Alaskan Case Study,” by J. Burt, T. Zhou, D.A. Rose, R. Grover, S. Ahmad, and J. Nemec, Schlumberger, and J. Dunston, Hilcorp, prepared for the 2018 SPE Western Regional Meeting, Garden Grove, California, USA, 22–27 April. The paper has not been peer reviewed.
This paper compares the results of gas identification and lithology identification using pulsed-neutron spectroscopy in openhole and casedhole environments. Most pulsed-neutron tools are run after casing; this study provides a unique opportunity to examine the effect of casing on spectroscopy by comparing casedhole measurements to measurements taken in the open hole before the casing was run.
Pulsed-neutron logging has evolved over the last 50 years, but the intrinsic physical measurements have remained unchanged, which means that operators cannot obtain a complete picture of the rock and fluids behind casing with conventional tools. However, advances in tool design and a new fast-neutron cross-section (FNXS) measurement provide for an alternative gas-identification technique. Gas in open holes is typically identified from neutron porosity and gamma-gamma density crossover. In casedhole environments, gamma-gamma density measurements are challenging because of the large casing and cement corrections needed. Previous gas identification in casedhole environments has relied on the formation hydrogen index (HI) or neutron porosity (TPHI) log and sigma.
In openhole environments, density and neutron porosity crossover is a typical gas identifier, but, in many instances, shale can mask the identification of gas. This is a common problem in some gas reservoirs in Alaska, and it leads to ambiguous interpretations about the gas saturation and potential producibility of different zones. Gas identification in casedhole environments is even more complicated because the density measurement is not commonly available.
The FNXS measurement responds primarily to formation atom density, for which most rocks, clays, and liquids have similar values. Comparatively, gas has a low atom density, and its presence will make the FNXS measurement read low. Thus, a gas pay zone can be differentiated from tight zones by the shift toward lower FNXS values. Also, the difference in FNXS between clean lithologies and clay is less than for sigma and TPHI, so FNXS, which is less affected by variable clay content, can be a more-robust gas indicator when variable clay is present.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29069, “How AI and Robotics Can Support Marine Mining,” by Peter Kampman, Leif Christensen, Martin Fritsche, Christopher Gaudig, Hendrik Hanff, and Marc Hildrebrandt, German Research Center for Artificial Intelligence (DFKI), and Frank Kirchner, DFKI and University of Bremen, prepared for the 2018 Offshore Technology Conference, Houston, 30 April–4 May. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission.
Marine mining initiatives open a new field of subsea operations. Offshore oil and gas sites are still located primarily in areas where divers can support maintenance and repair requirements, but future marine mining will take place in greater depths and with a complexity of machines that requires support from robotic systems equipped with a substantial amount of artificial intelligence (AI). Technologies are being developed that have the potential to support marine mining in all stages from prospection to decommissioning. These developments will likely have substantial influence in the oil and gas industry, itself searching for ways to maximize exploitation of assets.
Under Current Development Increasing Autonomous Underwater Vehicle (AUV) Intelligence. Commercial off-the-shelf AUVs rely mostly on acoustic and inertial sensors for their navigation. Speed measurements from a Doppler velocity log are combined with orientation values from gyroscopes and accelerometers to estimate current position. These updates are sometimes augmented by absolute-position fixes from an ultrashort baseline system. However, during such a mission, the inspection assets might not be located exactly at their expected positions. This might be because of incorrect positioning during installation, objects being dragged off location by fishermen, or sediments hiding a pipeline gradually from the view of standard sensors. Therefore, equipping modern AUVs with sensors and software that can search for, detect, track, and re acquire inspection targets is essential.
In addition, classical sensor suites consisting of cameras and sonars can be augmented with higher-resolution 3D sensing such as laser-line projectors (structured light). This enables an AUV’s onboard software to create a millimeter-precision 3D model of the asset, which can be compared with computer-aided-design models or previous-inspection-run data. By using a fully automated 3D-model cross-check, the AUV could detect asset deformations, defects, or marine growth, even while still submerged during the inspection run.
Seafloor AUV Support Infrastructure. Current AUVs have limited endurance, mostly because of limited battery capacity. Depending on the sensor suite, on-board data-storage space also can be a limiting factor. This causes AUV missions to run no longer than a few days at most, depending on AUV size and shape, propulsion, sensor efficiency, and environmental conditions in the deployment area.
Chris Carpenter, JPT Technology Editor A longstanding truism is that ideas that change one industry dramatically often are the result of innovations from a different industry altogether. In the realm of subsea exploration and production, with its high levels of risk and expense, concepts pioneered or used elsewhere are positioned to initiate important advances, a fact reflected in the three papers chosen for this year's feature on Subsea Hardware and Technology. Paper OTC 28051 uses the strength, weakness, opportunity, and threat (SWOT) analysis technique often used in organizational and personal strategybuilding to compare four different development concepts that hold promise for meeting the environmental and economic challenges posed by presalt fields in the Santos and Campos basins. In the realm of subsea exploration and production, with its high levels of risk and expense, concepts pioneered or used elsewhere are positioned to initiate important advances. Finally, paper OTC 29069 delves into the world of marine mining, where developments in artificial intelligence and robotics are redefining the roles of autonomous underwater vehicles (AUVs).
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28051, “Subsea Concept Alternatives for Brazilian Presalt Fields,” by Kevin Buckley and Ricardo Uehara, Shell, 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.
This paper identifies and compares four subsea-development concepts for typical Brazilian presalt deepwater applications on the basis of generic system functional requirements; the strength, weakness, opportunity, and threat analysis method (SWOT); and comparative cost/benefit analysis. The paper provides a fast-track approach to perform screening assessment of multiple subsea concepts.
Subsea development concepts for presalt regions such as those offshore Brazil have followed a replication methodology primarily based on a satellite configuration with flexible risers and flowlines. While this concept has several strengths, the associated scope of the operation incurs considerable cost. This concept, in addition to three others, is outlined in this paper. The concepts discussed include the following:
The objective of this paper is not to select the best option; rather, it is to discuss these options on the basis of application, objectives, premises, and field characteristics. Common characteristics of the Brazilian presalt fields are provided in the complete paper, and its Fig. 13 summarizes the SWOT analysis for all four concepts.
In this configuration, each well is connected directly to the host by two dedicated flowlines/risers: The production well has one production and one service flowline/riser, while the injection well has one gas-injection and one water-injection flowline/riser. Each well has an umbilical connected directly to the host. Thus, each tree has three connection modules located on the tubinghead spool (THS), one for each flowline and one for the umbilical. A pigging loop inside the THS allows for fluid displacement, double-sided depressurization, and round-trip pigging of the flowlines. The subsea-controls system is multiplexed, with a subsea-control module on each tree.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191296, “An Improved Correlation Approach To Predict Viscosity of Crude-Oil Systems on the NCS,” by Jørgen Bergsagel Møller, SPE, Knut Kristian Meisingset, SPE, and Ibnu Hafidz Arief, Equinor, prepared for the 2018 SPE Norway One Day Seminar, Bergen, Norway, 18 April. The paper has not been peer reviewed.
An accurate estimation of viscosity values is imperative for optimal production and transport design of hydrocarbon fluids. Consequently, precise and robust empirical correlation models are highly desired. While the literature contains numerous correlation models, most of these are inadequate for predicting accurate oil viscosity with unbiased data. This paper aims to develop new and improved empirical viscosity correlations through available field measurements on the Norwegian Continental Shelf (NCS).
The most-accurate viscosity correlation method makes use of the material balance of compositional information, which implies that a comprehensive pressure/volume/temperature (PVT) report is required. Such PVT reports usually include oil viscosity, which makes the correlation model redundant in many cases. Often, the only information available related to the fluid property is the solution gas/oil ratio (GOR), temperature, American Petroleum Institute (API) gravity, and pressure.
The empirical correlations in the literature have established categories to correlate oil viscosity for dead, gas-saturated, and undersaturated oil. The dead-oil correlations are used to predict the viscosity at standard conditions, when no gas is left in solution. All correlations from the literature ex press dead-oil viscosity as a function of API gravity and temperature. The second category is defined as a function of dead-oil viscosity and solution GOR and is applied when the fluid is at, or below, the saturation pressure. The latter correlation is normally expressed as a function of saturated oil viscosity, bubblepoint pressure, and reservoir pressure. The undersaturated-oil-viscosity correlations are applied when the reservoir pressure increases beyond the saturation pressure. This study investigates the statistical performance of 10 dead-oil, eight saturated, and five undersaturated oil-viscosity correlations.
Traditionally, the correlation models present an explicit mathematical expression based on field measurements to predict viscosity, while this paper presents three different correlation methods. Two methods are recognized as surrogate models to predict the viscosity properties, called the radial basis function network (RBFN) and kriging. In contrast to the traditional correlation models, these techniques do not present a mathematical correlation, because the models make use of a statistical approach with more consideration of the variation in input variables to predict the output. The kriging method demonstrated results superior to those of the empirical correlations. The third and last approach is an optimization algorithm called particle-swarm optimization (PSO). The technique recalculates the coefficients of the discussed correlations from the literature while maintaining the functional form of the expressions.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187040, “Dynamic Data Analysis With New Automated Work Flows for Enhanced Formation Evaluation,” by M.A. Proett, SPE, S.M. Ma, SPE, N.M. Al-Musharfi, SPE, and M. Berkane, SPE, Saudi Aramco, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed.
Petrophysical work flows are designed primarily to process static data for traditional openhole logs, which can provide estimates of porosity, saturation, lithology, and mineralogy. However, these estimates normally have a high degree of uncertainty and formation testing and sampling (FTS) data often are required for reservoir-condition calibration. This paper bridges the gap between operational petrophysicists and FTS specialists, introducing an automated work flow by which petrophysicists can conduct FTS jobs.
Wireline formation testers (WFTs) were commercialized in the late 1950s; drilling formation testers (DFTs) were introduced more recently. The primary benefits for FTS by means of wireline (e.g., WFT) or drillpipe (e.g., DFT) tools always has been a link between openhole log static volumetric formation evaluation and dynamic reservoir properties such as reservoir pressure, mobility, and fluid-sample composition, with many more applications under development using advanced testing tools and methods. However, FTS always has faced challenges with the integration of formation-tester data into the petrophysical work flow, limiting the ability to take full advantage of this valuable source of dynamic data.
Current work flows normally involve having an FTS specialist evaluate openhole log analyses, plan testing and sampling jobs, monitor data acquisition and quality-control (QC) results, and report on the final data interpretation. Thus, an FTS specialist should hold a wide spectrum of expertise, including FTS-tool use and data analysis and openhole logging and log analysis, as well as reservoir engineering and reservoir dynamics. Consequently, few petrophysicists are truly qualified to be FTS specialists. Therefore, automating FTS work flows is desirable.
Automated FTS Work Flow
In recent years, new automated methods have been introduced to speed up FTS data delivery. In automated QC data processing, real-time pressure tests are given a rating on the basis of criteria such as pressure stability, temperature stability, drawdown mobility, radius of investigation, and supercharging. More recently, methods have been published that can identify test sequences automatically. Similar methods have been implemented in at least one commercial software offering that demonstrates the benefit of automating the tedious process of selecting testing events manually. By combining the automated QC with the test-event selections, the analysis of data can be automated for real-time monitoring and post-job data processing objectively. With the testing data being processed automatically and the valid or best results being selected from each test sequence, automatically identifying reservoir fluid-flow behaviors is possible.
Carpenter, Chris (JPT Technology Editor)
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 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.
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.
Carpenter, Chris (JPT Technology Editor)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190312, “CO2-Foam Field Pilot Test in Sandstone Reservoir: Complete Analysis of Foam-Pilot Response,” by P.D. Patil, T. Knight, A. Katiyar, SPE, and P. Vanderwal, The Dow Chemical Company; J. Scherlin, SPE, Fleur De Lis Energy; P. Rozowski, SPE, The Dow Chemical Company; M. Ibrahim and G.B. Sridhar, SPE, Schlumberger; and Q.P. Nguyen, SPE, The University of Texas at Austin, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed.
This paper presents an analysis of a CO2-foam-injection pilot in the Salt Creek Field, Natrona County, Wyoming. The pilot was successful in demonstrating deeper conformance control and improvement in sweep efficiency, which resulted in 25,000 bbl of incremental oil. A 22% decrease in the amount of CO2 injected also was realized as a result of better use of CO2 compared with the baseline.
Foam-assisted CO2 enhanced oil recovery (EOR), commonly referred to as CO2-foam EOR, has been proposed as an effective technology for correcting sweep inefficiencies caused by gravity segregation and reservoir heterogeneity. The central concept of CO2-foam EOR is the in- situ generation of a viscous emulsion of CO2 and water stabilized by a surfactant at reservoir conditions. Because the apparent viscosity of a CO2/water/surfactant system is much higher than that of CO2 itself, the mobility of CO2 is significantly reduced. In the reservoir, the generation of foam occurs first in the zones preferentially swept by CO2, gradually diverting CO2 to unswept zones where oil saturation is typically higher. An important feature of the CO2 foam is that the foam strength, and hence the mobility reduction, weakens in the zones where there is substantial oil saturation. As a result, the foam does not interfere with the CO2 displacement process once the CO2 is diverted into zones with substantial oil saturation.
Salt Creek Foam Pilot
Although the CO2 flood in the Salt Creek Field, begun in 2004, has been very successful, certain isolated patterns were seen to exhibit high CO2 production and inefficient CO2 use, most likely because of the channeling of fluids through high-permeability, low-volume zones and the gravity override of the injected fluid. A CO2-foam pilot was undertaken to test whether these conditions could be remediated.
An inverted-five-spot pattern in the Phase V area of the field was screened as the best candidate for the CO2-foam EOR pilot (Fig. 1). The pilot injector was labeled as 22SE30 and the four production wells to be monitored were wells 15SE30, 14SE30, 26SE30, and 28SE30.
While other papers have been devoted to the Salt Creek foam pilot, this paper focuses on the injection-well response, the interwell tracer analysis, and the production response from the monitored producer wells in the pilot area. The authors discuss the injection and production responses for 2 years and 8 months of data. The foam injection in the field was completed in June 2016.