The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
The combination of extended-length horizontal drilling and high volume hydraulic fracturing has led to previously unimaginable production increases, yet the recovery potential of unconventional oil and gas resources remains largely unrealized. Recovery factors for unconventional oil and gas wells are typically reported at < 20% in gas shale reservoirs and < 10% in the oil plays.
Neutrally buoyant ultra-lightweight proppants have been demonstrated to effectively provide production from fracture area that is otherwise unpropped and thus, non-contributive with conventional sand/slickwater hydraulic fracturing processes. Production simulations illustrate that treatment designs incorporating neutrally buoyant ULW proppant treatment designs tailored for contemporary unconventional well stimulations deliver cumulative production increases of 30% to over 50% compared to the typical large volume sand/slickwater treatments. Unfortunately, production simulation results may not sufficiently lessen risk uncertainties for operators planning high-cost multi-stage horizontal stimulations. Therefore, several field trial projects using the neutrally buoyant ULW proppant in extended-length horizontal unconventional wells are currently in progress to validate the production simulations.
Since the initial 4-stage fracturing stimulation incorporating neutrally buoyant ultra-lightweight proppant in 2007, deployment has occurred in fracture stimulating hundreds of oil and gas wells spanning multiple basins and reservoirs. Most of the wells are vertical or relatively short lateral wells common to asset development practices predating the unconventional shale completions mania, but many were targeted at the same unconventional reservoirs as the current multi-stage horizontal completions. Several published case histories have documented the production enhancement benefits afforded by the legacy ULW proppant wells, but questions remained as to how those lessons might be correlated to provide engineers confidence in the current production simulations.
Well completion and production information was mined from the various accessible databases for the neutrally buoyant ULW proppant wells. The scope of the legacy data compiled for analysis was limited to the reservoirs common to the current field trials and production simulations, ie. unconventional oil and gas shale reservoirs. Production performance contributions of neutrally buoyant ULW proppant in past applications were compared with the production uplift observed in applications and/or simulated application of neutrally buoyant ultra-lightweight proppant fracturing treatments in current multi-stage horizontal reservoirs.
The lessons learned from this investigation provide the practicing engineer the means to confidently assess production simulation data for multi-stage horizontal unconventional completions incorporating neutrally buoyant ulw proppant in the treatment designs.
Ren, Bo (The University of Texas at Austin) | Male, Frank (The University of Texas at Austin) | Wang, Yanyong (The University of Texas at Austin) | Baqués, Vinyet (The University of Texas at Austin) | Duncan, Ian (The University of Texas at Austin) | Lake, Larry (The University of Texas at Austin)
The objectives of this work are to understand the characteristics of oil saturation in residual oil zones (ROZs) and to optimize water alternating gas (WAG) injection strategies. ROZs occur in the Permian Basin and elsewhere, and operators are using CO2 injection for enhanced oil recovery (EOR) in these zones. ROZs are thought to be formed by the flushing effect of regional aquifer flow acting over geological time. Both the magnitude of oil saturation and the spatial distribution of oil differ from water-flooded main pay zones (MPZs).
We conducted flow simulations of CO2 injection into both synthetic and realistic geologic reservoirs to find the optimal injection strategies for several scenarios. These simulations of CO2 injection follow either man-made waterflooding or long-term natural waterflooding. We examined the effects of CO2 injection rates, well patterns, reservoir heterogeneity, and permeability anisotropy on optimal WAG ratios. Optimal is defined as being at minimal net CO2 utilization ratios or maximal oil production rates).
Simulations of CO2 EOR show that the optimal WAG ratio for the ROZs is less than 1 (ratio of injected water and CO2 in reservoir volumes), and it depends, but in qualitatively different ways, upon the well pattern and reservoir heterogeneity. The optimal WAG ratio tends to increase with changing from inverted 9-spot (80-acres) to inverted 5-spot (40-acre) or increasing reservoir heterogeneity. The ratios for ROZs are consistently less than those observed in the same geologic models experiencing CO2 injection after traditional (man-made) waterflooding. This is because the water saturation caused by slow regional aquifer flow (~1ft/yr) differs from that created by traditional waterflooding. In ROZs, water prevails almost everywhere and thus it is less needed to ease CO2 channeling as compared to MPZs.
This work demonstrates that optimal WAG ratios for oil production in ROZs are different from those in traditional MPZs because of oil saturation differences. Thus, commingled CO2 injection into both zones or directly copying WAG injection designs from MPZs to ROZs might not optimize production.
Standard approaches to optimization under uncertainty in reservoir simulation require use of multiple realizations, with variable parameters representing operational constraints and actions as well as uncertain scenarios. We will show how appropriate use of local optimization within the simulation model, using customized logic for field management strategies, can bring improved workflow flexibility and efficiency, by reducing the effort needed for uncertainty iterations.
To achieve meaningful forecasts for an ensemble of uncertain scenarios, it is important to distinguish between different types of decision. Investment decisions, such as facilities sizing, depend on global unknowns and must be optimized for the complete ensemble. Operational actions, such as closing a valve, can be optimized instantaneously for individual scenarios, using measurable information, although subject to constraints determined at a global level. In this study, we implement local optimization procedures within simulation cases, combining customized objective criteria to rank reactive or proactive actions, with the ability to query reservoir flow entities at appropriate frequencies.
The methods presented in the paper can be used for reactive response modeling for smart downhole control; optimization of ESP/PCP pump performance; and implementation of production plans subject to defined downstream limits. For selected cases, we compare the advantages and disadvantages of the local optimization approach with standardized "big-loop" uncertainty workflows. The methodology can significantly reduce optimization costs, particularly for high-frequency actions, achieving similar objective function values in a fraction of the time needed for post-processing optimizers. Use of tailored scripting provides the capability to modernize the logic framework for field management decisions, with realistic representation of smart field equipment and flow entities at any level of complexity.
Use of efficient workflows as described in this paper can reduce the cost of multiple realization studies significantly, or enable engineers to consider a wider range of possible scenarios, for deeper understanding and better risk mitigation.
Dommisse, Robin (University of Texas) | Janson, Xavier (University of Texas) | Male, Frank (University of Texas) | Price, Buddy (The University of Texas at Austin) | Payne, Simon (Ikon Science) | Lewis, Andrew (Fairfield Geotechnologies)
Modern reservoir characterization approaches can be greatly aided by incorporating all available data and interpretations in a three dimensional geomodel. Our goal is to offer a regional perspective to augment the interpretations from local, field-scale 3D models developed by the industry. In this work we highlight the benefits of continuous development of the geomodel for the characterization of the facies architecture of an unconventional play.We generated a three dimensional, faulted Delaware Basin geomodel, containing over 1 billion cells, including stratigraphic, petrophysical, core description, and production data for the Bone Spring and Wolfcamp intervals. The model is based on over 7,000 correlated wells, 650 wells with facies interpretations and approximately 9,000 horizontal production wells with analyzed decline curves and completion data. Additionally, a high-quality 3D seismic volume in the northeastern part of the Delaware Basin reveals the complex stratigraphic architecture of key producing intervals in the Permian Basin. The 3D volume, combined with regional 2D seismic lines, enabled refining the interpretation of the stratigraphic architecture of the Wolfcampian to Guadalupian shelf margin. This allows us to relate the slope to basin strata imaged in the 3D seismic to the well-established stratigraphic architecture of the surrounding platforms. The 3D seismic volume reveals the seismic geomorphology of several key intervals. There are two areas of focus: 1) Testing of the facies model derived from log and core analyses using different deterministic and stochastic attribute distribution techniques; and 2) Exploring the influence of geological trends on productivity. This work demonstrates the value of a multiscale, regional perspective to the practice of 3D reservoir characterization in the Delaware Basin.
In the Midland Basin of west Texas, produced water volumes have historically been disposed into shallow intervals (i.e., Grayburg-San Andres). Over the last decade, the rapid growth in unconventional resource development has resulted in a significant increase in the volume of produced water leading to pressure gradient differences between shallow disposal zones and deeper intervals. These conditions have created drilling challenges and have prompted operators to test additional zones suitable for produced water disposal. In recent years, the Early Ordovician Ellenburger (ELBG) reservoir has become an alternative disposal interval to shallower reservoirs.
The Ellenburger Group of west Texas, a prolific producing reservoir, is part of an extensive carbonate system best known for karst development associated with prolonged subaerial exposure and intervals of high secondary porosity in fracture breccias generated by subsequent cave collapse. Many authors have described fracture occurrence and karst-related breccias of the ELBG, both of which impact productivity at the reservoir scale within the fields and make regional correlations particularly challenging. Ellenburger depositional facies have been described by previous workers in equivalent units across west and central Texas, and textural analysis of high-resolution electrical borehole images from recently drilled disposal wells, combined with core observations, shows corresponding porous intervals to be present in the Midland Basin.
This paper describes the generation of a regional model of porosity distribution within the Ellenburger and assesses the important differences in depositional environment and diagenetic history that exist among the internal units of the ELBG that may impact salt water disposal (SWD) well performance. For example, the Upper ELBG is dominated by fracture porosity in breccia fabrics associated with collapsed cave systems, while the Lower ELBG exhibits preserved porosity associated with original depositional textures. The regional model was tested using multiple datasets: image logs, core descriptions, electric logs from more than 400 well penetrations, and injection data from recent well tests. The integration of these datasets has resulted in a suite of maps of the key stratigraphic intervals within the ELBG that offer the greatest potential for disposal. Additionally, the integration of well performance with observed regional geologic trends was used to identify and tier key performance drivers for deep SWD injection performance, resulting in refined performance maps that can be used for strategic placement of deep SWD wells.
Wilson, Tawnya (Pioneer Natural Resources) | Handke, Michael (Pioneer Natural Resources) | Loughry, Donny (Pioneer Natural Resources) | Waite, Lowell (Pioneer Natural Resources) | Lowe, Brandon (Pioneer Natural Resources)
Over the last decade, the growth of unconventional resource development in the Midland Basin has significantly increased the disposal of produced water volumes. Disposal into the historic Grayburg-San Andres (GYBG-SNDR) reservoir has resulted in a dynamically changing pore pressure environment relative to deeper producing formations which is important to consider when planning drilling operations throughout the basin. A deep understanding of the GYBG-SNDR geology is imperative for reservoir management to ensure that produced water disposal does not hinder oil and gas production operations. This study describes the geologic controls on porosity and permeability distributions in GYBG-SNDR across the Midland Basin by utilizing core, modern well log suites, 3D seismic data, and saltwater disposal (SWD) well data.
In 2017, Pioneer acquired more than 1,000 feet of core in three wells over the GYBG-SNDR injection interval which were used to describe the depositional and diagenetic facies and calibrate a petrophysical model for a basin-wide well log dataset. The resultant log curves were used to construct maps describing the abundance and regional distribution of each lithology, which validated and further refined the depositional model. Observations resulting from the integration of the lithology maps, 3D seismic data, well log correlations and core were used to divide the basin into three distinct areas based upon the dominant lithologies and stratigraphic architecture. The three areas are separated by two major shelf margins representing a significant sea level drop at that time. These basin-wide trends provide a regional geologic framework in which to analyze SWD well performance.
Numerous geologic maps were created and tested against quality-checked and normalized SWD well performance data. Despite some scatter in the data (due to the differences in how the wells are operated, completed, and maintained) a positive linear correlation was found between SWD well performance and permeable dolomite footage. Additionally, anhydrite is most abundant in the northeastern part of the basin and is qualitatively associated with a decrease in permeable dolomite thickness, and therefore performance. Mapped matrix permeability is enhanced by fracture permeability related to syndepositional margin collapse and reactivation of older faults during the Laramide Orogeny. These features are documented throughout the Midland Basin using proprietary 3D seismic datasets and have been shown to be conduits for fluid flow resulting in dissolution and further dolomitization in some areas.
Yang, Junjie (Baker Hughes, a GE Company) | Karam, Pierre (Baker Hughes, a GE Company) | Cozyris, Kristian (Baker Hughes, a GE Company) | Hustak, Crystal (Baker Hughes, a GE Company) | Doherty, James (Riley Exploration – Permian, LLC) | Allen, Carmen (Riley Exploration – Permian, LLC)
As a well-known tight oil dolomite reservoir in Texas, San Andres formation has attracted broad attention about horizontal drilling and development strategy. To optimize the oil recovery and asset’s economics, the aim of the study was to use an integrated approach to understand reservoir heterogeneity and performance, determine optimal landing zone and its impact on production, understand fracture geometry using different pumping schedules, and the optimal cluster spacing. In addition, the potential benefit of a refrac and infill drilling program was also investigated.
To tackle the optimization problem, an integrated reservoir modeling workflow was developed. Starting with a 1-D geomechanical model which captures the in situ stress profile and rock mechanics, hydraulic fracture modeling was developed to history match the treatment process, and therefore a comprehensive fracture geometry can be estimated. In the interim, a geological model with populated reservoir properties was established based on the offset data including petrophysical logs, imaging logs and cores. After calibration, the dynamic reservoir model was built to test multiple sensitivity runs for an optimized field development strategy.
Geological modeling separated the field into two models to study the variation of properties on the east and west side. The east section shows a higher porosity and lower saturations. Those water saturations increase below the main pay zone indicating a potential water source. In addition, special core analysis shows a strong oil-wet nature of the reservoir rock. In the east section, sensitivity runs included infill development and variations in landing depth. It is noted that the production is not sensitive to landing zone because fracture geometry is primarily controlled by vertical stress profile. In the west section, sensitivity runs included refrac, infill drilling, and a greenfield development plan with variations on well spacing and completion design. The observation shows tighter well spacing or cluster spacing accelerates the oil production in early time, while yielding similar long term oil recovery and shows a combination of refrac and infill drilling yields a 21% incremental oil production beyond the base case.
This study provides valuable information about the workflow to develop tight oil plays by describing a detailed case study. The result also sheds light on the optimized field development strategy for analogous fields.