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Results
Summary Originally discovered in 1993, the Stag oil field, located on the Northwest shelf of Western Australia, has produced more than 58 million bbl since production began in 1998 (Goodacre et al. 2000). The field is shallow (680 m subsea), encompassing highly unconsolidated and highly permeable sandstone. Reservoir depletion, unconsolidated rock, water breakthrough, and sand production have created conditions under which infill-drilling campaigns have become increasingly problematic in the Stag field in recent years. There have been numerous papers documenting the history of the Stag field (McDiarmid et al. 2001; Muecke et al. 2002; Wibawa et al. 2008). On three recent infill wells, the intermediate 12¼-in. intervals were drilled and cased with casing-while-drilling (CWD) technology with a rotary-steerable system (RSS). This was used to navigate wellbore congestion, to drill designer well paths to avoid "incoherencies" [a seismic attribute that is mappable and correlates with drilling problems (Chima et al. 2012)], to land the horizontal section, and then to drill horizontal tangent sections out to the initial reservoir penetration (liner point). The CWD applications progressed from a "new technology" trial to a stretch reach and performance goal, to finally successfully being used as a key enabling technology to drill a well that might otherwise be undrillable because of instability issues. The directional CWD 12¼-in.-hole intervals were drilled from just below the 13-⅜in. surface casing to the 9⅝-in.-casing point, building from 25° inclination to horizontal and holding thereafter. This program (the first applications of this type in Australia) resulted in two consecutive world-record runs. The result is that CWD is a viable enabling technology that will be used to drill future Stag infill wells and should be considered as a viable alternative on other drilling projects. This paper will discuss the identification of the technology application, planning, implementation, results, and lessons learned. This paper will end with a notional conversation regarding CWD becoming a mainstream method.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Oceania > Australia > Western Australia > North West Shelf > Muderong Shale Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Kangaroo Trough > Greater Gorgon Development Area > Athol Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-209-P > Stag Field (0.99)
- (2 more...)
Summary Steam-assisted gravity drainage (SAGD) is one of the successful thermal-recovery techniques applied in Alberta oil-sands reservoirs. When considering in-situ production from bitumen reservoirs, viscosity reduction is necessary to mobilize bitumen, thereby flowing toward the production well. Steam injection is currently the most effective thermal-recovery method. Although steamflooding is commercially viable, condensation-induced water hammer (CIWH) resulting from rapid steam-pocket condensation can be a challenging operational problem. In steamflooding, steam is injected through a well down to the reservoir, warming it to temperatures of 150 to 270°C (302 to 518°F) to liquefy the bitumen inside the reservoir (Garnier et al. 2008; Xie and Zahacy 2011). The liquefied bitumen then drains to a lower well through which it is produced to the surface. In this process, steam pockets can become entrapped in subcooled condensate inside either the injection or the production tubing, causing a rapid collapse of the steam pocket. This type of rapid condensation is commonly referred to as "steam hammer." In this study, three different scenarios are explored to better understand steam-hammer situations in SAGD wells. These scenarios are at injectors or producers during the startup phase (or circulation phase), in the injection tubing during the injection phase, and in the production tubing during the injection phase. Modeling each of these scenarios indicates that a steam-hammer occurrence is likely in two of the three scenarios, but that its incidence can be mitigated. The likely scenarios for a steam-hammer occurrence are in either the injection or the production tubing during the startup phase, and in the injection tubing during the injection phase. Steam-hammer occurrences during the circulation period can be controlled by lowering the injection pressure and controlling water drainage into the reservoir. Flow shocks that occur as a result of countercurrent flow limiting (CCFL) are very likely to take place in the injection tubing during the injection phase but can be controlled by injecting at a higher steam quality. The least likely scenario for a steam-hammer occurrence is in the production tubing during the injection phase. This is because the produced (or breakthrough) steam temperature would need to be more than 20°C higher than the produced-liquid temperature to start a water-hammer condition.
- North America > United States (1.00)
- North America > Canada > Alberta (1.00)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Hangingstone Oil Sands Project (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > B1 Well (0.99)
Summary Augmented waterflooding is when a component is coinjected with water to modify the fractional-flow curve. Examples include polymer flooding, surfactant injection, low-salinity waterflooding, and carbonated-water injection (including applications related to carbon dioxide storage). The numerical simulation of these processes is a challenge for several reasons: The appropriate physical behavior needs to be incorporated consistently into empirical models of the fractional flow, whereas the solutions should minimize numerical dispersion, allowing the correct and accurate tracking of compositional variations. Lower-order numerical simulations of these processes give excessive front smearing, requiring many thousands of gridblocks in one dimension to resolve the fronts adequately, rendering the predictions from 3D simulations dubious at best. These erroneous predictions are not caused by phase dispersion (the improper prediction of water velocity)—as in black-oil simulation, in which the effect is less significant—but occur because of the coupling of compositional dispersion with fractional flow. Small errors in composition alter the fractional flow, causing the development of incorrect wavespeeds. The same effect is also seen in compositional simulation of gas injection. We propose a simple method for streamline-based simulations that substantially reduces numerical dispersion. The method is rooted in the assumption of segregated flow within a gridblock. After comparing numerical and analytical results in one dimension, we implement the method into a 3D streamline-based simulator of polymer flooding that also incorporates a physically based model of the fluid rheology. We demonstrate that traditional simulation methods can vastly overestimate recovery, potentially leading to poor injection design and management decisions. We demonstrate the utility of our approach by suggesting optimal strategies for the design of polymer injection on the basis of our improved simulation technique.
- Asia (0.93)
- North America > United States > Texas (0.28)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract From the 1940s through the 1980s, the work of such researchers as Purcell, Leverett, Swanson, and Thomeer provided methods for predicting flow properties, particularly permeability, based on capillary pressure curves measured on rock-mercury-vacuum systems. Although these methods met with considerable success, they have been largely overshadowed, particularly in recent years, by the rapid development of network and direct models. This paper reports on a study of 24 samples from an Offshore Ghana formation of Turonian age. The paper demonstrates that the work of Purcell, in particular, can be used to provide primary predictions of permeability (that is, predictions without any flexible fitting parameters) provided that mercury porosimetry and formation factor measurements are available, either on identical or companion samples. The predictions are good to within a range of factors between 0.5 and 2, with a mean error of less than 35%. This accuracy is remarkable considering that the range of permeability is seven decades and that the data were not collected for the specific purpose of the study. An experimental protocol is suggested that should improve further the already excellent results. The applicability of the method to drill cuttings is discussed. Also, a suggestion for a method of applying the proposed technique to digital rock results is presented. Finally, the paper explores reasons behind the success of the predictions and suggests what types of reservoirs are expected to provide similar successes.
- Africa (0.90)
- Europe > United Kingdom (0.46)
- North America > Canada (0.30)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164820, ’Probabilistic and Deterministic Methods: Applicability in Unconventional Reservoirs,’ by C. Coll, SPE, and S. Elliott, BG, prepared for the 2013 EAGE Annual Conference and Exhibition/SPE Europec, London, 10-13 June. The paper has not been peer reviewed. Reserves- and resources-evaluation methods in unconventional reservoirs are different from those for conventional reservoirs. Depending on the phase of the resource play, a deterministic, probabilistic, or hybrid method may be required, with the most effective method evolving from deterministic toward probabilistic as the resource play moves from the early phase to the mature phase. To define the best method to use in a particular area, the evaluator should first identify the phase of the resource play and evaluate the amount of data available. Introduction For unconventional reservoirs, classification systems similar to those for conventional reservoirs can be used (Fig. 1). These systems include prospective resources, estimated contingent resources at discovery, followed by reserves, with maturation linked to the phases of the resource play. As the resource play matures and technologies are screened, the development projects are better defined. Sections of the estimated resource volumes may be assigned to the contingent- resources subclasses using, for instance, the SPE Petroleum Resources Management System (PRMS) that recognizes the technical and commercial maturation toward reserves. Because unconventional accumulations are pervasive and developed with high-density drilling, well counts are typically large, making statistical analysis of well performance feasible. As a result, probabilistic techniques may be more appropriate to understand the uncertainty ranges of estimated ultimate recovery (EUR) per well and associated confidence levels. Extrapolation of results requires careful consideration of the geology and engineering characteristics of a particular area to predict well productivity. This analysis could be more intricate than that for conventional reservoirs because of the short production history and the particularly complex displacement mechanisms that may be happening in these reservoirs. For the estimation of resources in both conventional and unconventional reservoirs, it is important to understand the effect of reservoir uncertainties and development plans. Geological uncertainties such as gross rock volume, porosity, permeability, hydrocarbon saturation, and reservoir continuity have a large effect on in-place volumes. Engineering uncertainties (e.g., relative permeability, capillary pressures, viscosities, aquifer properties) affect the physical processes in the reservoir during the production of hydrocarbons, determining gas/oil recoveries and, finally, the ultimate reserves/resources.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Deterministic methods (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 158497, ’Integrated Asset Modeling for Reservoir Management of a Miscible WAG Development on Alaska's Western North Slope,’ by R.D. Roadifer, SPE, ConocoPhillips Alaska; R. Sauve, Schlumberger; R. Torrens, SPE, Schlumberger Middle East; H.W. Mead, SPE, N.P. Pysz, SPE, and D.O. Uldrich, SPE, ConocoPhillips Alaska; and T. Eiben, ConocoPhillips Canada, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed. An integrated-asset-model (IAM) approach has been implemented for the Alpine field and eight associated satellite fields on the western Alaskan North Slope (WNS) to maximize asset value and recovery. The IAM approach enables the investigation of reservoir- and facilities-management options under existing and future operating constraints. The technology used for managing the fields consists of fullfield compositional reservoir-simulation models for each reservoir integrated with a pipeline-surface-network model and a process facility model. Developing an IAM Reservoir-Management Needs. As with the construction of any reservoir or surface model, the first step in developing an IAM is to define with as much clarity as possible the objectives in undertaking such an endeavor. A detailed list of all possible objectives for creating an IAM covering all possible development and operational situations that might occur would be quite extensive. As is often the case, however, simply identifying the “big rocks” will allow the finer details of those leveraging aspects to be identified and planned for in the development of the IAM. The Alpine field anchors the westernmost oil-production and -processing facility on Alaska’s North Slope (Fig. 1). Discovered in 1994, the Alpine field is in the Colville River delta, 6 miles south of the Arctic Ocean and approximately 70 miles west of the Trans-Alaska Pipeline. The Alpine field began production in November 2000 and continues development today. Subsequently, satellite fields, including the Fiord-Nechelik, Fiord-Kuparuk, Nanuq-Kuparuk, Nanuq-Nanuq, Qannik, and Alpine-Kuparuk, have been brought on line and continue to be developed. Additionally, several fields in the National Petroleum Reserve have the potential to be developed. The common theme across all these developments is that they are or will be produced through the Alpine Central Facility (ACF). The ACF is a single-train processing facility. The only significant fluid that leaves the ACF is the sales oil. All other gas not used for fuel or lift must either be blended for injection as miscible injectant (enriched lean-gas injectant) or be injected as lean gas into two black-start gas-injection wells. All produced water must be reinjected and, for pipeline-integrity reasons, must be segregated from imported makeup seawater used for injection.
- North America > United States > Alaska > North Slope Borough (1.00)
- North America > United States > Texas > Bexar County > San Antonio (0.25)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Alpine Field > Kingak Formation (0.99)
- Asia > Middle East > Israel > Tel Aviv District > Southern Levant Basin > National Field (0.97)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 16523, ’Oman's Large-Carbonate-Field Production Improvement Through Integrated Well, Reservoir, and Facility Management,’ by S.M. Al-Khadhuri, M.M. Al-Harthi, and A. Alkalbani, Petroleum Development Oman, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A carbonate field developed by Petroleum Development Oman is one of the largest fields in the Sultanate of Oman and has been running for more than 4 decades. An integrated wells, reservoir, and facility management approach has been implemented to create more focus and discipline with the aim of achieving an efficiently monitored and controlled asset and highly synchronized multiteam actions. Introduction The field is located in the north of the Sultanate of Oman, and it is one of Oman’s largest fields. The reservoir layers dip uniformly at 15° to the northeast (Fig. 1). The field is a highly complex carbonate reservoir of the Natih formation and is subdivided into seven units, Natih A through Natih G, and the Shuabia reservoir. It has been running since 1967 and continues to contribute significantly. The development strategy began with natural depletion with vertical wells and followed with two mechanisms, gas/oil gravity drainage (GOGD) and waterflood. The GOGD process concentrates more on fractured reservoir rock, while the waterflood process targets the layers with a relatively low degree of fracturing. The GOGD development consists of five crestal gas-injection wells and rows of down-flank producers that tap oil from a fractured oil rim. The reservoir pressure is managed by gas injection. The gas-injection rates are set to replace voidage and to maintain reservoir pressure. For the matrix wells, the reservoir pressure is managed by waterflood (water injection). This combination of different drive mechanisms in a highly fractured reservoir that yields to interference and gas/water short-circuiting makes the management of the field very challenging. To overcome these challenges, an integrated well, reservoir, and facility management strategy has been established in a way that ensures integration with multiple disciplines and uses many tools. As a result, an improvement in production has been seen that reflects successful implementation of the strategy. Wells and Reservoir Reviews Wells are reviewed on a yearly basis in order to have a systematic approach for reviewing wells. Approximately 26 sectors (more than 450 wells) from different reservoirs have been reviewed collaboratively. Multidisciplinary involvement from the well and reservoir management (WRM) team, the development and planning (DP) team, and the new oil (NO) team, and alignment to mature identified activities, played a crucial role in effectively sharing ideas and lessons learned and implementing activities.
- Asia > Middle East > Oman (1.00)
- North America > United States > Mississippi > Marion County (0.41)
- Asia > China > Beijing > Beijing (0.25)
Higher temperatures and pressures in reservoirs add complexity to corrosion mitigation. February 2013 - Oil and Gas Facilities 23 acquisition and management, action protocols, models, from a variety of crudes has led to a renewed industry verification, and some form of validation, he said. The additional attention has encouraged corrosion. Operators can change the material every time it researchers to develop new techniques for mitigating the fails, replacing the tubing, surface lines, or even vessels when effects of corrosion and for monitoring the effectiveness of they fail. The second alternative is to change the material of those agents.
- Europe (0.46)
- Asia > Middle East > Saudi Arabia (0.15)
- North America > United States > Ohio > Denmark Field (0.89)
- Europe > United Kingdom (0.89)
- Europe > Netherlands (0.89)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (2 more...)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165138, ’Produced-Water-Reinjection Design and Uncertainty Assessment,’ by Jalel Ochi, Dominique Dexheimer, and Vincent Corpel, Total EP France, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, the Netherlands, 5-7 June. The paper has not been peer reviewed. Produced-water reinjection (PWR) is an important strategy for deriving value from waste water, but its implementation can face challenges related to injectivity and safety issues. The first objective of a PWRI-design study is to supply water-quality specifications, and the second is to supply injection-pressure specifications. The objective of this paper is to detail how water quality and injection pressure are deduced when uncertainties of input data are considered. Introduction Before any PWRI design commences, a feasibility study is performed to assess any compatibility issues and evaluate the risk of scaling and souring and the viability of the project. Bacteria growth and corrosion of the installations have to be tackled and mitigated upstream in the early phase of the project. The first objective of a PWRI-design study is to determine the water quality in terms of optimum total-suspended-solid (TSS) and oil-in-water (OIW) contents, which could remain in the water after treatment and which would enable maintaining the injectivity under PWRI during the field life. These two parameters allow design of the water-treatment installations. The second objective is to determine the pressure needed to achieve PWRI sustainability; the pump power and the injection-network size will be designed on the basis of this pressure. PWRI-Design Approaches There are three main approaches to PWRI design. The first approach is based on analogs and correlation laws, the second is based on laboratory experiments, and the third uses simulations with predictive models. Of these, the most effective is that of running simulations with predictive models, because this allows simultaneous determination of the water quality and the injection pressure needed to sustain injectivity. Field evidence indicates that, whatever the quality of produced waters, PWRI in matrix (or radial injection) regimes inexorably leads to a continuous decline of injectivity. PWRI is viable only in a fractured regime, and pressure and water quality have to be designed for long-term efficiency of this regime. Fractured injection, though a complex process to model, is now considered to be a part of the PWRI strategy for field developments. New PWRI simulators are based on modules describing the flow in both matrix and fractured regimes coupled with a module describing the plugging inside and around the well, as well as plugging within and around the fracture, if any. Compared with conventional fracture software used for stimulation jobs, the fracture module takes into account the thermal and poroelastic effects generated by the high leakoff of cool water.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.53)
A unique fluid-pulse technology has generated impressive increases in ultimate oil recovery in applications in North and South America and the Middle East. Developed in Alberta, Canada, the fluid-pulse technology has proved its ability to recover oil previously left behind in fields thought to be depleted or uneconomical--potentially billions of barrels globally. In addition to driving the phenomenal growth of the Alberta oil sands, Canada's oil industry has developed a depth and breadth of experience in some of the world's harshest conditions. Those harsh conditions often create opportunities for new technologies to show their capabilities to a largely cautious industry. A recent report by the United States Energy Information Administration notes that the US imported about 45% of the 18.8 million B/D of crude oil and petroleum products it consumed in 2011.
- North America > United States (1.00)
- North America > Canada > Alberta (0.74)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.56)