Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Aamodt, G. (ConocoPhillips Skandinavia AS) | Abbas, S. (ConocoPhillips Co) | Arghir, D. V. (ConocoPhillips Skandinavia AS) | Frazer, L. C. (ConocoPhillips Co) | Mueller, D. T. (ConocoPhillips Co) | Pettersen, P. (ConocoPhillips Skandinavia AS) | Prosvirnov, M. (ConocoPhillips Skandinavia AS) | Smith, D. D. (ConocoPhillips Co) | Jespersen, T. (Halliburton Co.) | Mebratu, A. A. (Halliburton Co.)
This paper discusses a field case review of the processes used to identify, characterize, design and execute a solution for a waterflood conformance problem in the Ekofisk Field that developed in late 2012. The Ekofisk Field is a highly-fractured Maastrichtian chalk reservoir located in the Norwegian sector of the North Sea. Large scale water injection in the field began in 1987 and overall the field has responded well to waterflood operations. However, fault reactivation coupled with extensive natural fractures and rock dissolution has resulted in some challenging conformance issues. In late 2014, a solution was executed to control this problem. Details of the diagnostic efforts and how this data was used to identify, characterize and mitigate an injector/producer connection through a void space conduit (VSC) will be outlined and discussed. These diagnostics include pressure transient analysis (PTA), interwell tracers, injection profiles, seismic mapping, fluid rate analysis, fluid composition and temperature monitoring. The importance of this data analysis is the key element necessary to select an effective solution.
The selected approach involved pumping a large tapered nitrified cement treatment into the offending injector, which is believed to be the single largest nitrified cement operation ever pumped within the oil industry. Because of extremely rapid communication with an offset producer, a protective gel was used to reduce the risk of cement entry into that producer. A brief review of alternative mitigation options and the reasons for selecting the nitrified cement treatment will be discussed. Additionally, a complete review of the shutoff technique, product, damage mitigation strategy, and complications associated with timing and coordination in an offshore environment will also be discussed. Finally, a summary of lessons learned, job execution observations, post-treatment performance results over the past three years, and forward plans will be presented. Based on these results it is believed that there are a number of opportunities to add strong value through conformance engineering.
This paper describes a new chemical EOR numerical model capable of simulating surfactant and polymer floods. We present the highlights of a highly efficient and robust IMPES implementation within a legacy, in-house gas-oil-water compositional simulator. The additional computational overhead, over say a waterflood calculation, is on the order of only 20% for large scale (type pattern model) simulations. We present performance results both in serial as well as parallel (multi-processor) mode.
Flow within all three Winsor Type environments is modeled, with the ability to transition between the different types. The effects of a separate microemulsion (ME) phase are accounted for. Temperature effects on surfactant phase behavior as well as on adsorption are also considered. Other important physical effects that are modeled include phase trapping and oil bypassed by surfactant, near wellbore polymer injectivity and the reduction of surfactant adsorption associated with a sacrificial agent such as alkali. Gas phase is included in the model.
The model has been extensively benchmarked against another reservoir simulator. We also present some validation results at the laboratory as well as at the field scale.
Noble, L. (Schlumberger Oilfield Services) | Govil, A. (Schlumberger Oilfield Services) | McCann, C. (Schlumberger Saudi Arabia) | Obando Palacio, G. A. (Schlumberger Oilfield Services) | Knutsen, O. (ConocoPhillips Co) | Nesland, B. (ConocoPhillips) | Mueller, D. T. (ConocoPhillips)
As the fields in the North Sea mature, many of wells undergo permanent well abandonment or permanent abandonment of a section of the well for consequent well sidetracking. Compliant procedures for well abandonment as per Norwegian Continental Shelf regulatory requirements necessitates the presence of double barriers to isolate permeable formations/sources of inflow. To achieve a compliant plug-and-abandonment case in situations where casing cement is part of the primary or secondary well barrier (forming part of an external well barrier envelope), casing cement must be verified by logging to ensure a good formation-to-cement-to-casing seal. However, if inner casing is expected to be cemented across the depth where the permanent cement plug (forming an internal well barrier element, WBE) is planned to be set, then the inner casing must be milled so that the outer casing can be logged to verify the barrier seal. Traditional casing milling operations are costly and time consuming, often lasting for several days. This paper describes an alternative way of verifying an external WBE when the inner casing presents an obstruction for outer casing cement evaluation.
Like all production companies Occidental Petroleum (Oxy) is continually searching for new and creative ways to increase production and lower operating costs. Artificial Lift is a major focus due to the large annual expenditures on equipment and electrical power consumption. Oxy faces unique challenges in its Enhanced Oil Recovery (EOR) operations in the Permian Basin where miscible carbon dioxide (CO2) and water flooding are utilized resulting in wells with high gas to liquid ratios (GLR) that challenge the gas handling capabilities of electrical submersible pumps (ESP's). While initially designed for high temperature steam flood applications Geared Centrifugal Pumps (GCP's) have several design advantages that make them attractive to use as an alternative lift option. A GCP is an artificial lift system which utilizes a Progressing Cavity Pump (PCP) drive head and rod string to drive an ESP style centrifugal pump through a downhole speed increasing transmission. The GCP design has the rate capacity of an ESP, but eliminates a downhole motor and power cable. By eliminating the downhole motor the GCP design delivers the ability to run a dip tube below the pump without a shroud through the perforations which should improve natural downhole gas separation. In order to test the performance of the GCP system Oxy chose to conduct a trial in three Permian Basin wells in one of its miscible CO2 floods. The key objective of the trial was to compare the performance of the GCP system with the previously installed lift methods to confirm if there is an opportunity to increase drawdown, increase daily up time, improve system efficiency, and increase run life. As of the writing of this paper two GCP systems have been installed as part of the trial with one of the installations still being in operation. This paper will present the details of the trial and the results that have been obtained thus far as well as challenges and lessons learned.
Livingston, Erica (ConocoPhillips Norway) | Bjornen, Kevin (ConocoPhillips) | Burkhead, David W. (ConocoPhillips Co) | Gilbert, Trey (ConocoPhillips Co) | Kent, Anthony W (ConocoPhillips Stavanger) | Leitch, John (ConocoPhillips Co) | Zhou, Leon (ConocoPhillips Co)
This paper covers the development, laboratory testing, and field testing of acid-soluble-plug (ASP) technology as a viable completion alternative to wireline- or tubing-conveyed perforating. The ASPs are installed in a preperforated reservoir liner and dissolve when soaked in acid, allowing access to the reservoir. This allows the technology to be easily applied in reservoirs in which matrix acid jobs or acid-fracturing techniques are used. The ASP technology was developed to reduce risk and cost associated with wireline- and tubing-conveyed perforating. ASPs were designed, manufactured, and field tested in both 5-in. and 7.625-in. reservoir liner sizes for wells in the Ekofisk field. The combination of laboratory testing and large-scale field testing influenced the design of the ASPs as well as the additives used in the acid systems used to dissolve them. From concept to initial field implementation, the process of ASP-engineering development took more than 2 years. The concept was in the beginning field-tested in deviated injectors, with ASPs installed in the deepest section of the reservoir liner. The field tests proved the ASP concept before depending on the technology in a horizontal producer with an uncemented, tubing-inliner completion solution. The field tests showed that acid soaking dissolved the ASPs in the downhole environment and allowed efficient acid stimulation of the reservoir. It also reduced the number of wireline runs necessary to complete the well. When field tested in a tubing-in-liner completion application, installation of the ASPs in the reservoir liner eliminated tubingconveyed-perforating runs. The reservoir liner was uncemented with mechanical openhole packers for zonal isolation. The ASPs provided a pressure-tight reservoir liner to set the packers against and eliminated fluid loss during the running of the inner completion string. Optimization of this technology is an ongoing process. The plug design itself continues to evolve as well as the operational steps to minimize the soaking time necessary to dissolve the plugs and to gain access to the reservoir.
This paper outlines our selection of well completion design based on the results of sand production prediction for each of the development wells and the total sand production to be expected from the field. The methodology on the formation failure and modeling analysis for sand production and sand rate prediction is provided for the HPHT gas and gas condensate field located offshore in the UK’s Central North Sea. Sand production caused by the failure of reservoir formations through pressure depletion and drawdown pressure could lead to a significant loss in well production, well/facility damage or ultimately total well failure. The key objective of this evaluation and sand rate prediction analysis was to develop a well completion design that will deliver effective sand control throughout the producing life of the field.
Over the field life it is both critical and prudent to predict the sanding potential of a given reservoir during continuous well production for any completion design under consideration. This paper illustrates our comprehensive geomechanics investigation for sanding potential and sand rate prediction analysis for all the planned wells to be drilled and completed in the very thick sandstone reservoirs. We’ll also show that if the reservoir rock strength and its variability along depth are properly measured for each well (through well core testing and log data analysis), the conditions that induce sand production issues for each specific interval could be predicted. In addition, the most important factors contributing to sanding problems have been identified to be the rock strength, flowing bottom-hole pressure, reservoir pressure, in-situ stresses, and flow rate. Therefore if permeability distribution and oil/gas and water saturations were measured (for each well) in addition to the reservoir rock strength, the optimal completion method to reduce the likelihood of sand production problems without significantly impacting production could be found. A 3D non-linear elastic-plastic finite element model incorporated with a fluid-flow module (reservoir component) has been effectively used to conduct such analysis. The key findings from this investigation can be summarized as follows:
Solids removal from severely depleted wells remains a challenging intervention operation in the oil and gas industry. The various cleanout options that exist generally require significant expense, and may result in loss of potentially damaging fluids or permeability reduction to zones with low bottomhole pressures.
This paper will focus on several field trials in South Texas utilizing a fluid-based, formation-blocking agent as part of the cleanout circulating fluid. The blocking agent has been in use for several years in cement spacer systems as a lost circulation material (LCM) with favorable results. The blocking agent uses a modified, hydrophobic polysaccharide to form micelles. Under differential pressure the micelles adsorb and realign in a layer along the formation or perforation tunnel forming an impermeable seal effectively blocking the loss of fluids to the formation. With the formation blocked, the solids can be circulated out using a higher density fluid and at higher circulation rates than the low-pressure reservoir would support. When the well is returned to an underbalanced system, the micelles will disperse, returning the fluid to its original state and restoring permeability to near a pre-intervention level.
The case histories included in this paper are the first application of this material for well intervention operations outside a cement spacer application, and the results discussed show that the material performed remarkably well.
ConocoPhillips’ South Texas Lobo field is comprised of more than 1,700 active tight-gas wells. Development in the field has been primarily from the late 1970s to 2012 with more than 2,000 total wells drilled. The primary producing formations are in the Lobo Wilcox sands at depths from 7,000 to 13,000 ft with original reservoir pressure ranging from 4,000 to 9,000 psi. Most wells required propped hydraulic fractures because of the stacked sands with permeability ranging from 0.01 to 1 md. Many wells were completed with multiple hydraulic fractures because the sands are scattered over a height of 1,000 to 1,500 ft. Typically, wells in the field have produced 1 to 2 Bcf, but some have produced in excess of 28 Bcf; wells with higher cumulative production currently have reservoir pressure ranging from 300 to 1,000 psi.
Fill or bridges such as proppant, formation sand, salt and scale often cover the perforations and reduce or prevent production from the formation. Cleaning out these obstructions is usually first attempted by bailing with slickline, but when this is unsuccessful either coiled tubing (CT) or a workover rig is used. The primary challenge with using coiled tubing or a workover rig is that low bottomhole pressure in the wells makes it impossible to circulate solids to the surface. The hydrostatic pressure of the circulating fluid (nitrogen and low-concentration potassium chloride (KCl) water) combined with frictional pressure loss between the cleanout tubing and production tubing can be significantly higher than the reservoir pressure can support. In this case solids cannot be removed from the well and liquid is lost to the formation.
Based on the premises of anomalous diffusion models in fractal porous media, an alternative to dual-porosity based formulations of flow in fractured unconventional reservoirs is presented. The new formulation is implemented in the trilinear flow idealization for a fractured horizontal well in a tight formation and verified by using the asymptotic cases. The results of the new model are compared with the dual-porosity based trilinear flow formulation and the differences and similarities are delineated. A discussion of the characteristics of the pressure and derivative responses obtained from the trilinear anomalous-diffusion model is provided and related to the fractal nature of fractured media. Physical interpretations are also assigned to fractional derivatives and the phenomenological coefficient of the fractional flux law. It is shown that the anomalous diffusion formulation does not require explicit references to the intrinsic properties of the matrix and fracture media and thus relaxes the stringent requirements used in dual-porosity idealizations to couple matrix and fracture flows. The trilinear anomalous-diffusion model should be useful for performance predictions and pressure- and rate-transient analysis of fractured horizontal wells in tight unconventional reservoirs.
Two common approaches to model naturally fractured media are the discrete fracture network (DFN) models and dual-porosity idealizations (Fig. 1). In discrete fracture network (DFN) models (Fig. 1A), it is possible to consider the details of each fracture and the distribution and connectivity of the fracture network. However, DFN models require extensive characterization studies and also lead to computationally inefficient models. In general, the level of detail that can be utilized from the DFN model is limited by the capabilities of the flow model, which will use the DFN model. Therefore, despite their potential, the DFN models are not the tool of choice for most routine engineering applications.
This paper presents the success story of an integrated approach to optimize the production performance of the Goldsmith Andector Unit (GANDU) in West Texas. All production is from the Clearfork formation, a typical carbonate reservoir characterized by large and discontinuous pay intervals with low reservoir energy and high residual oil saturation. This is a mature field which began re-development through a 20 acres infill drilling program in 2001, and has been under waterflood expansion since 2008. A multi-discipline team was commissioned to improve the production in the field. The team used an aggressive approach towards the development practices applied across the unit; from the reservoir engineering aspects, to the operational aspects. Reservoir characterization and numerical simulation work, in conjunction with classical methods, validated the 650 MMSTB of original oil in place in the reservoir; and validated the estimated Waterflood reserves. Also, operational guidelines were developed from the geological and engineering study. Through the operational aspect the team focused on the optimization of the base production, monitoring well performance, and detecting opportunities to optimize production through workovers, returning-to-production (RTP) jobs and recompletions. This paper details the systematic approach that was followed in order to achieve success including the geological characterization, the reservoir engineering approach, data acquisition, production monitoring, well automation, optimization of the field and development program for subsequent years. Details of the workflow implemented under the technical approach, best operational practices, lessons learned and path forward of the team are shown in the paper. As a result, the production of the field increased approximately 75% since 2001, with a total increase of 3000 BOEPD over a 2.5 year period.