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 The paper has not been peer reviewed.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 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 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.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190302, “Foaming Behavior of CO2-Soluble Viscoelastic Surfactant in Homogeneous Porous Media,” by Galang Ramadhan, The University of Texas at Austin; George Hirasaki, SPE, Rice University; and Quoc P. Nguyen, SPE, The University of Texas, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed.
Aqueous foam has been demonstrated to have promise in conformance-control applications. This paper explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. A distinguishing feature of this surfactant is its ability to dissolve in supercritical CO2 and to form wormlike micelles (WLMs) at elevated salinity. The presence of WLMs leads to an increase in viscosity of the aqueous surfactant solution. This paper investigates how the presence of WLM structures affects transient foam behavior in a homogeneous porous media (sandpack).
Aqueous foam is a dispersion of a gas in an aqueous phase with a surface-active agent (surfactant) to lower the interfacial tension between the two phases. Foam functions as an effective mobility-control agent because of its high apparent viscosity in porous media.
Foam’s mobility in porous media is also influenced by the media’s relative permeability. In porous media, foam’s ability to flow from one pore to another is heavily dependent upon overcoming the capillary forces imposed by the pore-throat constrictions. Because of this yield-stress requirement, a large portion of a foam system in a porous media is not mobile. This fraction of trapped foam could occupy up to 65% of total pore volume, depending on foam-injection quality, injection velocity, and porous-media morphology. Trapped foam severely reduces the effective permeability of gas moving through a porous media by reducing the number of conduits through which the foam can flow.
Addition of Polymer and Polymer-Like Structures
The addition of polymer to a surfactant solution typically increases a foam’s apparent viscosity. From the perspective of foam generation, the addition of polymer to a surfactant solution seems to decrease the rate of foam-generation events. With the addition of liquid-phase-viscosifying polymer, a greater pressure gradient needs to be applied to reach the onset of strong foam generation. The higher pressure-gradient requirement could translate to fewer foam-generation events and potentially limit the foam generation to the near-injection-well region. From the perspective of foam stability, addition of polymer seems to reduce the occurrence of lamellae destruction. Immediately after the formation of fresh foam bubbles, the lamellae are subjected to disturbance forces that reduce the thickness of the lamellae’s liquid phase (film). The thinning process continues until the film reaches a critical thickness at which the lamella is not stable and tends to coalesce. Polymer improves the stability of thick foam film by increasing its viscosity and reducing the rate of film drainage.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18914, “Extracting More From Wireline Formation Testing: Better Permeability Estimation,” by S.R. Ramaswami, P.W. Cornelisse, SPE, H. Elshahawi, M. Hows, and C.L. Dong, SPE, Shell, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2017 International Petroleum Technology Conference. Reproduced by permission.
The use of pressure-transient data in formation testing to describe reservoirs is considered mature technology, particularly when applied to data collected through production testing. The extension of this technique to data obtained using wireline formation testers (WFTs) has been gaining momentum in the industry; however, the integration of these outputs with other measurements of data is not always straightforward. The complete paper presents different methods of using pressure-transient data from WFTs; many of these methods are summarized here.
Pressure-Transient Data From WFTs
Perhaps the most widely used form of WFT pressure-transient data is that derived from small-volume drawdowns and buildups during a pressure test. The volume of fluid withdrawn from the formation, and the resulting depth of the pressure pulse, is limited to the near-wellbore region. The flow regime that develops during these tests is typically spherical flow in an infinite medium; hence, the mobilities derived from these sorts of pressure-transient tests are spherical mobilities and need to be converted to radial mobilities to quantitatively compare the tests. Additionally, pretest-derived mobilities have two fundamental challenges: the unknown effect of skin caused by drilling damage and the uncertainty of fluid viscosity to be used to convert the resulting mobility to permeability.
The other common application of pressure-transient information during wireline-formation tests uses pressure data over a much longer interval. During an extended pumping station with a WFT, a particular flow-rate history is applied to a well and the resulting pressure changes are recorded. From the measured pressure response, and from predictions of how reservoir properties influence that response, an insight into the reservoir can be gained. In order to make these predictions, it is necessary to develop mathematical models of the physical behavior taking place in the reservoir. Fig. 1 shows the difference between the volume investigated with a small-volume pressure test and an extended pumpout station. The most-common well model that is used when interpreting WFT data is the vertical limited entry model.
Fluid flow in porous media is governed by the diffusivity equation. To derive it in its simplest form, the following assumptions and simplifications have to be made:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183743, “Maintaining Injectivity of Disposal Wells: From Water Quality to Formation Permeability,” by Ali A. Al-Taq, Mohammed N. Al-Dahlan, and Abdullah A. Alrustum, Saudi Aramco, prepared for the 2017 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 6–9 March. The paper has not been peer reviewed.
An extensive laboratory study was carried out with two objectives: to evaluate the effect of water quality on injectivity of disposal wells with reservoir core plugs and to restore injectivity of damaged wells. In this paper, water-quality guidelines to minimize or prevent formation damage are recommended. On the basis of laboratory work, a novel chemical treatment was successfully applied to restore injectivity of several damaged disposal wells. This novel treatment reduced the long operation time and cost of a typical treatment practice while effectively stimulating the well.
Effect of Water Quality and Formation Permeability on Injectivity
Water quality has a major influence on the injectivity of injection and disposal wells. Poor injection or disposal-water quality can compromise the effective injectivity of even high-quality sandstone or carbonate formations. Source water used for injection often contains solids, which can reduce permeability of the formation around the wellbore.
Solids-particle damage depends on particle size of the solids, oil present in the injected water, and the average pore-throat diameter of the formation. If the particles are larger than the average pore-throat diameter of the formation, then the particles cannot penetrate the pores. As a result, an external filter cake with permeability lower than that of the formation will form (Fig. 1a). Another type of injectivity impairment occurs when the size of the particles present in the injected water is smaller than the average pore-throat diameter of the formation. These particles will invade the formation and bridge at some pores (Fig. 1b). As solids concentration in the injection water is increased, the rate of permeability decline becomes greater. Obviously, if the size of the particles is significantly smaller than the average pore-throat diameter of the formation (Fig. 1c), then the particles will flow through the formation without causing any damage. As a result, there will be no loss of injectivity for a long period of time.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179119, “A Well-Performance Study of Eagle Ford Gas Shale Wells Integrating Empirical Time/Rate and Analytical Time/Rate/Pressure Analysis,” by A.S. Davis and T.A. Blasingame, Texas A&M University, prepared for the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9–11 February. The paper has not been peer reviewed.
The purpose of the complete paper is to create a performance-based reservoir characterization by use of production data (measured rates and pressures) from a selected gas-condensate region within the Eagle Ford Shale. The authors use modern time/rate (decline-curve) analysis and time/rate/pressure (model-based) analysis methods to analyze, interpret, and diagnose gas-condensate well-production data. Reservoir and completion properties are estimated; these results are then correlated with known completion variables. The time/rate and time/rate/pressure analyses are used to forecast future production and to estimate ultimate recovery.
Production-Analysis Work Flow
The data required for the completion of the proposed methodology include well-history files, daily-rate and flowing-pressure measurements, and laboratory pressure/volume/temperature (PVT) and fluid-analysis reports. The following diagnostic plots are used to identify potential errors or abnormalities in the production data:
In addition to checking the integrity and correlation of production data, the authors also use the following diagnostic plots to establish the reservoir model and flow regimes:
Note that, for the diagnostic plots, an incorrect estimate of the initial reservoir pressure will yield plots that show skewed trends or clumping or scattering of data points, particularly at early production times.
On the basis of the information gathered from the diagnostic plots and well-history files, nonrepresentative production data points that are likely the result of nonreservoir effects or operational changes such as well-cleanup effects, liquid loading, well recompletions, well workovers, or choke changes are filtered. The diagnostic plots are prepared with the filtered production data to identify the flow regimes experienced by a given well. It is of primary importance to recognize if the well is still in transient flow or has already entered boundary- dominated flow because it allows determination of which of the time/rate relation models is appropriate for the given production data.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180181, “Catalog of Well-Test Responses in a Fluvial Reservoir System,” by J.L. Walsh and A.C. Gringarten, Imperial College London, prepared for the 2016 SPE Europec featured at the 78th EAGE Conference and Exhibition, Vienna, Austria, 30 May–2 June. The paper has not been peer reviewed.
Well-test analysis in fluvial reservoirs remains a challenge because of the depositional environment conducive to significant internal heterogeneity. Analytical models used in conventional analysis are limited to simplified channel geometries and, therefore, fail to capture key parameters such as sand-body dimensions, orientations, and connectivity, which can affect control-fluid flow and pressure behavior. The complete paper aims at a better understanding of the effect of channel content in complex fluvial channel systems on well-test-derivative responses.
Geological Modeling. 3D geological models with a centrally located well were generated and populated with varying fluvial geologies. A 6950-m×6950-m×300-ft geological model was set up that allowed the averaging effects of the heterogeneities and the reservoir boundaries to be visible on the derivative at late times.
Modeling the geology of a fluvial system is challenging because of changes in channel amplitude, amalgamation, and other processes through geological times, which yield highly variable distribution and shapes of fluvial deposits. Field X was modeled as isolated elliptical sand bodies and channel bodies, with sand-body dimensions of 105 m (width)×420 m (length)×5 ft (thickness) for the base case. The sand and channel bodies are schematically represented in Figs. 1 and 2. Object-oriented modeling was used instead of stochastic, sequential indicator simulation and Gaussian simulation to retain control over the modeling parameters.
Numerical Simulation. The corresponding pressure and derivative dynamic responses were generated using a proprietary finite-element simulator with a uniform grid and a fine local grid refinement (LGR) around the wellbore. The fluid was black oil at a reservoir pressure greater than the saturation pressure, and the relative permeability to water was low enough to limit water movement within the model.
Results and Discussion of Base-Case Model
A drawdown of 115 years was simulated for a geological model 6950 m×6950 m×300 ft with a cell size of 50 m×50 m×5 ft in the x, y, and z directions, respectively (total cell count without LGR=1,159,260), with a fine Cartesian LGR around the wellbore to reduce numerical artifacts around the wellbore (total cell count with LGR=1,327,200). The model consists of two facies. All simulations were performed without including wellbore dynamics or mechanical skin.