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.
This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are high.
Hydraulic fractures, whether created during a DFIT or larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure, which may be caused by near well friction or tortuosity but, may also result in more complex fractures in multiple planes.
Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional ISIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators.
Analysis of FFEP and ETFRs identified in the DFIT PTA analysis method combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
Ibrahim Mohamed, Mohamed (Colorado School of Mines) | Ibrahim, Ahmed Farid (Apache Corporation) | Ibrahim, Mazher (Apache Corporation) | Pieprzica, Chester (Apache Corporation) | Ozkan, Erdal (Colorado School of Mines)
The instantaneous shut-in pressure (ISIP) serves as an indication of the excess pressure in the hydraulic fracture due to the effect of fluid viscosity and pressure required to break the formation at the fracture tip. The ISIP value will be close to or at the fracture propagation pressure and will be greater than the fracture pressure. The ISIP is often estimated to be the pressure after the pumps are shut down, and the beginning of a pressure decline. Many approaches have been developed to estimate the ISIP from the falloff data. The development of these approaches is attributed to the persistent trials due to the difficulty of quantifying the ISIP value accurately. Giving bottomhole pressures, ISIP can be estimated by subtracting the friction pressure drop from bottomhole pressure. This approach tends to overestimate the value of ISIP as it doesn't account for friction near the wellbore or through the perforations. Another common approach to estimate ISIP is by drawing a straight line on the early falloff portion of the Diagnostic Fracture Injection Tests (DFIT).
Previous studies show that the choice of ISIP affects the net pressure calculations, but not the slope of the derivative curves and the flow regime identification. This paper presents field cases where the values of ISIP affects the interpretation of the reservoir characteristics. Thus, the determination of accurate ISIP is very crucial.
This paper reviews the previously proposed approaches for determining the ISIP and provide a state of the art simple method to determine ISIP from non-ideal falloff data. The ISIP determined from the proposed method is verified by examination of the semi-log derivative plot, and the interpreted reservoir characteristics were found to be consistent with both field and lab observations. The method was validated using field DFITs falloff data from high-pressure dependent leakoff formations as well as formations that yield normal leakoff pressure dependent.
The novelty of the proposed method is in the simplicity of determination of ISIP and the consistency with the field observations. A number of field examples from the Barnett shale are illustrated using mechanisms previously proposed in the literature as well as the method presented in this paper. The later provided consistent ISIP values after multiple iterations. Subsequently, the reservoir characteristics and calculated parameters were uniform within the same pad of wells.
Diagnostic fracture injection tests (DFIT's), or "mini-fracs" are often used to gauge many reservoir and fracture design parameters. However, DFITs are not always conducted in conjunction with the main completions work. This paper proposes a novel workflow to determine the instantaneous shut-in pressure (ISIP) from readily available completions data. This is a valuable parameter in itself as related to the least principal in-situ stress states as demonstrated by the stress change relationships near faults in
Directly using completions data from fracture stimulation operations, the authors have leveraged on the water-hammer signature in bottom-hole pressure data during completions to process the ISIP for each completions stage. Within this study, completions data from ~2100 stages from ~300 horizontal Montney formation wells were analyzed. A MATLAB script was used to automate the derived ISIP stress trends over the Montney formation and to deduce the ISIP in a consistent format.
This novel workflow also validates the expected in-situ stress trends at depth, with a relationship of high ISIP gradients closer to fault zones similar to stress change behaviour as shown in
Considering the continued push for higher fluid and sand loading in industry in the development of unconventional assets as an economic driver, there also exists a large and tangible corporate citizenship opportunity of mining real time completions dark data with the possibility of relating that live feed as a prescriptive tool to mitigate reactivation of critically stressed faults. This case study focuses on the Montney formation as a basis for processing easily available data from standard operations in an effort of systematically designating areas prone to seismicity risk in future hydraulic fracturing operations based on automated real-time analytics of dark data.
Plugs for hydraulic fracturing generally are pumped into horizontal wellbores. Initially, the goal was to get the plugs to depth without careful consideration of the amount of water used in the pumping. As the industry has grown, a better understanding of pump-down methods and techniques has resulted in a realization that these pumping inefficiencies should be improved.
When completing a horizontal well using the plug-and-perf technique, water is required to push the bottom hole assembly (BHA), containing a frac plug, to the target depth. With over one million frac plugs having been pumped in North America, large data sets are available to quantify the pump-down efficiency of these operations. This past information, along with a working model of how pump down works, can be used to promote improvements in pump-down efficiency, reducing water usage and rig time.
The efficiency of the pump-down operation can be calculated based on pump time, displacement volume, and the actual volume of fluid pumped. This type of information can be recorded during operations. The pump-down efficiencies can be calculated as a percentage of actual versus calculated volumes pumped and is often expressed as a relational number, such as how much fluid is needed per 100 feet of casing. These numbers can be used as a metric for the amount of water and time required to move the plug to its desired location.
Over 10,000 frac plug pump downs from diverse North American regions were analyzed to attain a baseline for efficiency during frac plug pump down operations. The force, pressure, and fluid velocity effects acting on the BHA during pump down were analyzed to understand how to better quantify methods and designs that increase or decrease efficiency. Finally, procedures were mapped out on the operational units used in pump down to understand the potential impacts on efficiency.
The result is a guide on gauging pump-down efficiency of past operations while understanding methods to increase these efficiencies in the future. This framework can be used to view how a frac plug is pumped downhole while understanding the relationships that control its efficiency. This model can be used to evaluate past operations as well as design for future operations to increase overall efficiencies and decrease water usage and time on location.
During the hydraulic fracturing process, the fracturing fluid may cause water blockage, if the nearby secondary fractures subsequently close and get disconnected due to changes in effective stress distribution during flowback and production. The fluid inside the fractures could also get squeezed out upon fracture closure. The circumstances and detailed mechanisms associated with this phenomenon are still poorly understood. In this work, a coupling scheme for incorporating a pressure-dependent apparent permeability model in reservoir simulation is implemented. The numerical models are subsequently used to investigate the impacts of water blockage and apparent permeability modeling on gas production and water flowback.
A high-resolution 3D reservoir model is constructed based on the field data obtained from the Horn River shale gas reservoir. Stochastic 3D discrete fracture network (DFN) model is upscaled into equivalent continuum dual-porosity dual-permeability (DPDK) model by analytical techniques. A realistic DFN configuration is examined to simulate the potential scenarios of water blocking. An apparent permeability (Kapp) model that accounts for contributions of Knudsen diffusion, slip flow and surface pore roughness is introduced. In order to capture the pressure dependency, a novel coupling scheme is developed to facilitate the updating of Kapp and effective stress after a certain designated time interval. In addition, a novel method involving rock-type indicators is introduced to represent the open and closed states of secondary fractures, facilitating the modeling of stress-dependent closure of the secondary fracture system.
Fracture closure and the resulting water blockage would impact the gas production and water recovery, particularly if the near-well fractures are disconnected. Neglecting the effects of Kapp could essentially overestimate the contribution of hydraulic fracture for a certain observed gas production. The existence of secondary fractures could also enhance water loss, which is contrary to some conclusions in previous research where Kapp modeling and disconnected fractures are ignored. The impacts of shut-in duration and matrix multiphase flow functions are systematically studied. It is concluded that gas and water production would increase if less water is imbibed into the matrix during the shut-in period in the presence of disconnected secondary fractures. It is also observed that a shorter shut-in period may be beneficial to both water and gas recovery, where previous studies have reported no observable increase in gas production when secondary fracture closure was not considered.
This work presents a set of detailed simulation studies to examine the scenarios or conditions that may be responsible for water blockage, particularly in the presence of disconnected secondary fractures. A novel, yet practical, scheme is implemented to couple stress-dependent matrix apparent permeability and fluid flow, as well as to model pressure-dependent fracture closure. The modeling scheme can be readily integrated in most commercial reservoir simulation packages. The results have revealed several potential scenarios of water loss, along with the associated implications on optimal operational strategies and estimation of stimulated reservoir volume.
Connectivity of the pore system is crucial for production of hydrocarbons from unconventional resources. In shales, pore throats critically control and limit permeability. Even if larger pores are the dominant pore size, small pores throats could ultimately control the access to that pore space. Mercury injection capillary pressure (MICP) measurements are commonly made to determine pore throat size distributions. Results for shales usually show large injection volumes associated with pore throats just several nanometers in diameter. The existence of these small pore throats has also been confirmed by Focused Ion Beam/Scanning Electron Microscope (FIB/SEM) analysis. One of the unique properties of mercury is that it is non-wetting to both matrix phases present in organic-rich shales; therefore, it can access pore systems in both organics and inorganics. MICP measurements dynamically alter the pore structure through pore compressibility which intrinsically depends on the aspect ratios of the pores; crack like pores, with very high aspect ratios, may close at low pressures and may not be sampled by MICP. The connectivity of the pore space and how much of it is accessed by MICP remains poorly understood.
Here we report on shale samples that have undergone MICP followed by Micro X-ray Computed Tomography (μXCT) and FIB/SEM imaging. μXCT results show that not all regions of the shale samples were accessed uniformly by MICP. Mercury is observed going into fractures and penetrating into the shale matrix. The distance away from the fractures and the percentage of the sample volume accessed by mercury has been calculated. Some samples, such as the Tuscaloosa Marine Shale, showed mercury penetration throughout specific layers in the sample, whereas Eagle Ford samples showed mercury penetration more uniformly and on average of almost 150 μm away from the fractures with almost 60% of the entire sample volume accessed by the mercury. These μXCT results suggest that mercury is not fully accessing all the pore space of the sample even at 60,000 psi which corresponds to a pore throat radius of 1.8 nm.
Cryo FIB/SEM was used to further investigate mercury intrusion into the shale matrix at the nanometer scale. Frozen droplets of mercury were observed in pores as small as 30 nm which corresponds to an injection pressure of 6,000 psi. The mercury clearly accessed the organic pores and remained after pressure was reduced. This is also reflected in the hysteresis observed in the MICP spectra captured during pressurization and depressurization. The magnitude of the hysteresis is a consequence of the differences between pore bodies and pore throats. Like the μXCT, SEM results show that intrusion of mercury into the sample is not uniform indicating that many of the pores are not connected to the outside of the sample. These results suggest that pore connectivity in shales may be very limited, and the volume accessible may not extend far from fractures in the shales.
Unconventional resources such as Bakken shale have made a significant impact on the global energy industry, but the primary recovery factor still lingers from 5% to 15 %. Over the past ten years, a number of pilot tests for both gas and water injection or their cyclic injection have been implemented to improve oil recovery in the Bakken Formation. The available public data show that the injectivity is not a problem, but only a small increase in production. The obvious reason is unexpected early breakthroughs even with a relatively low reservoir permeability of around 0.03 mD. Lots of experimental and simulation studies have been conducted to investigate different mechanisms behind these improved oil recoveries. However, no one has succeeded to clarify this early breakthrough.
In this study, a simulation reservoir model, including two wells, is developed, whose properties are based on public data. In terms of hydraulic fractures for each well, their geometry and conductivities are evenly built. Furthermore, our geomechanical module is applied to capture the evolution of stress field and rock failure, where a Barton-Bandis model and a Mohr–Coulomb failure criterion are applied to model tensile and shear failure, respectively. Our simulation model coupled with the geomechanical module is then implemented to explain the performance of injection pilot test.
The results of this initial study clearly show the new fractures (frac-hits) induced by water injection connect the injection and production wells, resulting in the early water breakthrough. The stress field has also been altered by the production process to favor the formation of these fractures. This study highlights the importance of geomechanics during an IOR process; identifies the reasons for the early breakthrough and provides an insight view about how to improve oil production in the Bakken Formation.
It has often been reported that the peak production of a well drilled in tight formations is highly dependent on the fracture contact area. However, there is no efficient approach to estimate the fracture surface area at present. In this paper, we propose a method to calculate the fracture surface area based on the falloff data after each stage of the main hydraulic fracture treatment.
The created hydraulic fracture closes freely before its surfaces hit on the proppant pack, and this process can be recognized on the pressure falloff data and its diagnostic plots. The pressure decline rate during fracture closure is mainly caused by fluid leakoff from the fracture system into the formation matrix. For a horizontal well drilled in the same formation, we may assume the same leakoff coefficient among all stages, so the total fracture surface area can be calculated for all stages to meet the requirement of the fluid leakoff rate.
Wellbore storage effect, friction dissipation and tip extension dominate the early pressure falloff data. While the transient dominated by friction losses typically lasts about one minute, tip extension may end after about 15 minutes. Therefore, falloff data should be acquired for at least 30 minutes to observe a fracture closure trend. The fracture closure behavior can be identified on the G-function plot as an extrapolated straight line or on the Bourdet derivative in log-log plot as a late time unit slope. The behavior of the late unit slope depends on the pressure decline rate, or correspondingly, to the fluid leakoff rate. Therefore, the total fracture surface area can be estimated using hydraulic fracture design input values for formation leakoff coefficient and fracture closure stress. The calculated fracture surface area represents the combined area of primary and secondary fractures, effectively all fracture surfaces contributing to the fluid leakoff.
We applied the approach to all stages in a horizontal well that exhibit the fracture closure behavior. The approach shows promise as a straightforward way to estimate fracture surface areas that could, enable, in turn, an early estimate for the expected well performance.
Hui, Mun-Hong (Chevron Energy Technology Company) | Dufour, Gaelle (Chevron Energy Technology Company) | Vitel, Sarah (Chevron Energy Technology Company) | Muron, Pierre (Chevron Energy Technology Company) | Tavakoli, Reza (Chevron Energy Technology Company) | Rousset, Matthieu (Chevron Energy Technology Company) | Rey, Alvaro (Chevron Energy Technology Company) | Mallison, Bradley (Chevron Energy Technology Company)
Traditionally, fractured reservoir simulations use Dual-Porosity, Dual-Permeability (DPDK) models that can idealize fractures and misrepresent connectivity. The Embedded Discrete Fracture Modeling (EDFM) approach improves flow predictions by integrating a realistic fracture network grid within a structured matrix grid. However, small fracture cells with high conductivity that pose a challenge for simulators can arise and ad hoc strategies to remove them can alter connectivity or fail for field-scale cases. We present a new gridding algorithm that controls the geometry and topology of the fracture network while enforcing a lower bound on the fracture cell sizes. It honors connectivity and systematically removes cells below a chosen fidelity factor. Furthermore, we implemented a flexible grid coarsening framework based on aggregation and flow-based transmissibility upscaling to convert EDFMs to various coarse representations for simulation speedup. Here, we consider pseudo-DPDK (pDPDK) models to evaluate potential DPDK inaccuracies and the impact of strictly honoring EDFM connectivity via Connected Component within Matrix (CCM) models. We combine these components into a practical workflow that can efficiently generate upscaled EDFMs from stochastic realizations of thousands of geologically realistic natural fractures for ensemble applications.
We first consider a simple waterflood example to illustrate our fracture upscaling to obtain coarse (pDPDK and CCM) models. The coarse simulation results show biases consistent with the underlying assumptions (e.g., pDPDK can over-connect fractures). The preservation of fracture connectivity via the CCM aggregation strategy provides better accuracy relative to the fine EDFM forecast while maintaining computational speedup. We then demonstrate the robustness of the proposed EDFM workflow for practical studies through application to an improved oil recovery (IOR) study for a fractured carbonate reservoir. Our automatable workflow enables quick screening of many possibilities since the generation of full-field grids (comprising almost a million cells) and their preprocessing for simulation completes in a few minutes per model. The EDFM simulations, which account for complicated multiphase physics, can be generally performed within hours while coarse simulations are about a few times faster. The comparison of ensemble fine and coarse simulation results shows that on average, a DPDK representation can lead to high upscaling errors in well oil and water production as well as breakthrough time while the use of a more advanced strategy like CCM provides greater accuracy. Finally, we illustrate the use of the Ensemble Smoother with Multiple Data Assimilation (ESMDA) approach to account for field measured data and provide an ensemble of history-matched models with calibrated properties.