Wu, Weiwei (The University of Texas at Austin (now with Apache Corporation)) | Zhou, Junhao (Qmax Solutions) | Kakkar, Pratik (Siemens Corporation) | Russell, Rodney (The University of Texas at Austin) | Sharma, Mukul Mani (The University of Texas at Austin)
A great deal of evidence shows that hydraulic fracturing creates a large surface area of induced unpropped (IU) fractures that are too small to accommodate commonly used proppants and that, subsequently, close during production (Sharma and Manchanda 2015). Because of their enormous surface area, IU fractures can play an important role in hydrocarbon production if they can remain open during production. Therefore, the conductivity of these IU fractures under different stress conditions and when exposed to different fracturing fluids is of great importance.
In this study, core-scale IU fractures were created with preserved shale samples from the Eagle Ford and Utica formations. Samples with different mineralogies were selected to represent a broad cross section of representative samples. Great care was taken to ensure that the shale samples were preserved because large changes in shale mechanical properties caused by sample desiccation have been observed. The fracture conductivities of unpropped fractures created in each of the shale samples were measured as a function of closure stress by using nitrogen or brine. The unpropped fractures were exposed to several water-based fracturing fluids including neutral brine, alkaline brine (pH 11, 12), and acidic brine (pH<1), with or without clay stabilizers. The effects of fluid type, pH, clay stabilizers, shale mineralogy, and cyclic stress on IU-fracture conductivities were investigated. Batch tests also were performed to study the change of mechanical properties and fines production caused by fluid-shale interaction.
Our results show that unpropped fractures yielded conductivities that were 2 to 4 orders of magnitude lower than those of propped fractures, and were more susceptible to closure stress. Exposure to water-based fracturing fluids decreased the unpropped-fracture conductivity by one order of magnitude. The primary mechanism for the decrease was shale softening caused by exchange of water and ions between the native fluid of shale and the exposed fracturing fluid. Shale softening was observed in exposure to all brines tested, regardless of their pH. In addition to shale softening, fines generation also contributed to the reduction of unpropped-fracture conductivity when shales were exposed to alkaline or acidic brine. Amine-based clay stabilizers were able to control the unpropped-fracture conductivity impairment by reducing the amount of clay-based fines. However, they were not as effective at stabilizing nonclay fines. Shale mineralogy affected the unpropped conductivities in two ways: It controlled the mechanical properties of the native preserved shale, and also affected the fluid-shale interactions. A clear correlation was observed between mineralogy and stress dependence. Clay-rich samples showed the most stress sensitivity in the presence of water or brine at neutral pH, whereas the calcite-rich samples showed less stress sensitivity. High clay content also resulted in lower restored conductivity after cyclic stress. Mechanical properties of shale such as hardness and Young’s modulus, before and after fluid exposure, strongly correlated with the mineralogy of shales. Unpropped conductivity was more sensitive to cyclic stress than propped conductivities, and it dropped by 80% after one cycle of closure stress between 300 and 4,000 psi of closure stress. Clearly, it is shown that water-based fracturing fluids can affect conductivities of IU fractures in shales significantly, and these impacts need to be considered in the selection of fracturing fluids.
A coiled-tubing (CT)-acid-tunneling-stimulation technique has been successfully applied in the preceding 15 years on limestone and dolomite reservoirs around the world (the Middle East, southeast Asia, North America, South America, and Europe). Several case histories were presented in the past showing that this technique might bring significant benefits over other carbonate-stimulation methods in openhole wells. In this paper, the parameters affecting the predicted and achieved tunnel lengths are discussed for the first time. The acid-tunneling technique consists of pumping hydrochloric acid (HCl) through conventional CT and a bottomhole assembly (BHA) with jetting nozzles to create (without drilling) stable drainage holes (tunnels) into the reservoir pay zone. The BHA also includes a special kickoff tool, with two pressure-activated bending joints, that controls the tunnel-creation direction. The acid that is not consumed during the main tunneling process leaks into the reservoir rock, creating wormholes that improve the connectivity between the reservoir and the wellbore and positively influence well production. This acid-tunneling technique can potentially create numerous tunnels with different depths. The optimization of the tunnel-creation-depth selection is made by production-software simulation using such critical information as the well parameters (trajectory and size), available logs (image, resistivity, caliper, drilling), and past reservoir information.
The results from many field case histories involving the CT acid-tunneling technique from around the world were presented previously. However, many questions remain unanswered regarding the actual downhole tunnel-initiation/creation process. In this study, a detailed discussion of acid-tunneling modeling is included to answer some of those questions. The parameters affecting the predicted tunnel lengths and the parameters that could be monitored or adjusted to create the tunnels smoothly are discussed. This paper describes the CT acid-tunneling technology and discusses some of the most important questions regarding downhole CT acid-tunneling creation. The acid-tunneling-technique performance and benefits confirmed during field operations are presented.
This paper investigates the effects of high production rates on well performance for a casedhole gas well using two types of completion schemes: frac pack and gravel pack. We model fluid dynamics in the near-wellbore region, where the most dramatic changes in pressure and velocity are expected to occur, using computational fluid dynamics (CFD). The fluid-flow model is dependent on the Navier-Stokes equations augmented with the Forchheimer equation to study inertial and turbulence effects in regions where the velocity increases and decreases sharply over a relatively small length scale. Real-gas properties are incorporated into the momentum-balance equation using the Soave-Redlich-Kwong (SRK) equation of state (EOS) (SRK-EOS). The near-wellbore model is pressure-driven under steady-state and isothermal conditions. Well-performance curves are generated depending on simulation results for both completion schemes. Furthermore, we introduce the concept of rate-dependent pseudoskin factor to assess inertial and turbulence kinetic energy (TKE) losses under various pressure differential. Analysis of the simulation results suggests that the rate-dependent pseudoskin changes from negative at low gas-production rates to positive at medium-to-high gas-production rates. This is primarily because of the inertial and turbulence effects being triggered at a certain flow rate, which we define as the optimal operating point. We demonstrate that the gas-deliverability curve plotted along with the pseudoskin-factor curve allows us to estimate the optimal operating condition as the point where the rate-dependent pseudoskin is zero. An analytical model to estimate the optimal production rate is proposed as an extension to typical multirate tests.
Flare stacks must be monitored continuously to ensure ignition of released gases during the plant operation. Generally, the process of flare detection refers to detecting the presence or absence of a flare. Flare monitoring adds the capability of tracking the size of the flare to this process. By setting lower and upper monitoring boundaries, an alarm can be generated if the flare becomes too small or too big. Reliable flare-stack monitoring becomes crucial to ensure that no unburned toxic or waste gas is released into the atmosphere, causing environmental issues and possible fire hazards. It also gives the operator an extra handle to optimize the production process. In this paper, we introduce an automatic flare-detection and monitoring system. Our user-friendly system is computer-vision-based, plug-and-play, and designed as a built-in part of the camera. By taking advantage of the geometrical properties of the flare as well as temporal information obtained by video analytics, we create a monitoring system that is robust to various parameters such as wind direction. To the best of our knowledge, we are the first to present an automatic flare-stack-monitoring system with flare-size tracking and automatic event signaling. Our presented system has been tested for live monitoring in the Rotterdam Botlek area, The Netherlands. The preliminary results illustrate a reliable system that is free of false alarms.
The 3D hydraulic-fracture-simulation modeling was integrated with 4D time-lapse seismic and microseismic data to evaluate the efficiency of hydraulic-fracture treatments within a 1 sq mile well-spacing test of Wattenberg Field, Colorado. Eleven wells were drilled, stimulated, and produced from the Niobrara and Codell unconventional reservoirs. Seismic monitoring through 4D time-lapse multicomponent seismic data was acquired by prehydraulic fracturing, post-hydraulic fracturing, and after 2 years of production. The results from the simulation modeling and seismic monitoring show the significant effect of reservoir heterogeneity on hydraulic-fracture stimulation and hydrocarbon production.
A hydraulic-fracture-simulation model using a 3D numerical simulator was generated and analyzed for hydraulic-fracturing efficiency and interwell fracture interference between the 11 wells. The 3D hydraulic-fracture simulation is validated using observations from microseismic and 4D multicomponent [compressional-wave (P-wave) and shear-wave (S-wave)] seismic interpretations. The validated 3D simulation results reveal that variations in reservoir properties (faults, rock-strength parameters, and in-situ stress conditions) influence and control hydraulic-fracturing geometry and stimulation efficiency.
The integrated results are used to optimize the development of the Niobrara Formation within Wattenberg Field. The valuable insight obtained from the integration is used to optimize well spacing, increase reserves recovery, and improve production performance by highlighting intervals with bypassed potential within the Niobrara. The methods used within the case study can be applied to any unconventional reservoir.
Steam-assisted gravity drainage (SAGD) is a thermal-recovery process to produce bitumen from deep oil-sands deposits. The efficiency of the SAGD operation depends on developing a uniform steam chamber and maintaining an optimal subcool (difference in saturation and actual temperature) along the length of the horizontal well pair. Heterogeneity in reservoir properties might lead to suboptimal subcool levels without the application of closed-loop control. Recently, model-predictive control (MPC) has been proposed for real-time feedback control of SAGD well pairs based on real-time production, temperature, and pressure data along with other well and surface constraint information; however, reservoir dynamics has been represented using extremely simplified and unrealistic models. Because SAGD is a complex, spatially distributed, nonlinear process, an MPC framework with models that account for nonlinearity over an extended control period is required to achieve optimized subcool and steam conformance.
In this research, two novel work flows are proposed to handle nonlinear reservoir dynamics in MPC. The first approach is adaptive MPC, and includes continuous re-estimation of the model at each control interval. This allows the evolution of the coefficients of a fixed-model structure such that the updated system-identification model in the MPC controller reflects current reservoir dynamics adequately. Another approach, gain-scheduled MPC, decomposes the subcool-control problem in a parallel manner, and uses a bank of multiple controllers rather than only one controller. This ensures effective control of the nonlinear reservoir system even in adverse control situations by using appropriate variations in input parameters based on the operating region.
The work flows are implemented using a history-matched numerical model of a reservoir in northern Alberta. Steam-injection rates and liquid-production rate are considered input variables in MPC, constrained to available surface facilities. The well pair is divided into multiple sections, and the subcool of each section is considered an output variable. Results are compared with actual field data (in which no control algorithm is used), and are analyzed on the basis of two criteria: (1) Do all subcools track the set point while maintaining stability in input variables? and (2) Does the net present value (NPV) of oil improve with adaptive and gain-scheduled MPC? In general, we conclude that both adaptive and gain-scheduled MPC provide superior tracking of subcool set points and, hence, better steam conformance caused by adequate representation of reservoir dynamics by re-estimation of coefficients and multiple controllers, respectively. In addition, the results indicate stability in input parameters and improvement in economic performance. NPV is improved by 23.69 and 10.36% in case of adaptive and gain-scheduled MPC, respectively.
The proposed work flows can improve the NPV of an SAGD reservoir by optimizing the well-operational parameters while considering constraints of surface facilities and minimizing environmental footprint.
Takabayashi, Katsumo (INPEX Corporation) | Shibayama, Akira (INPEX Corporation) | Yamada, Tatsuya (ADNOC Offshore) | Kai, Hiroki (INPEX Corporation) | Al Hamami, Mohamed Tariq (ADNOC Offshore) | Al Jasmi, Sami M. (ADNOC Offshore) | Al Rougha, Hamad Bu (ADNOC Offshore) | Yonebayashi, Hideharu (INPEX Corporation)
This study aims to improve asphaltene-risk evaluation using long-term data. Temporal changes in asphaltene risks with gas injection were evaluated. In reservoirs under gas injection, the in-situ fluid component gradually changes by multiple contact with the injected gas. Those compositional changes affect asphaltene stability, causing difficulty in risk prediction using asphaltene models. This study aims to reduce the risk uncertainty depending on operational-condition changes.
Periodic upgrading of asphaltene models is essential for understanding the time-dependent changes of asphaltene risks. In a previous study, the asphaltene risk was evaluated for an offshore oil field in 2008 using the cubic-plus-association equation-of-state (EOS) models and using all the available data at the time. Additional experimental data were subsequently collected for a gas-injection plan. An additional study was performed that incorporated and compared the data sets.
According to the previous study recommendation, additional asphaltene laboratory studies were conducted using the newly collected samples. All the asphaltene-onset pressures (AOPs) detected in the new samples were higher than those found in the previous study. A large difference was observed between the past and recent AOPs in the lower reservoir even though the samples were collected from the same well. The asphaltene-precipitation risk increases considerably because the new study detected AOP at the reservoir temperature, whereas no AOPs were detected in the previous study. The difference may be attributed to saturation-pressure increase. Next, the numerical asphaltene models were revised; the re-evaluated asphaltene-risk estimations were higher in the lower reservoir and slightly higher in the upper reservoir than the past ones. The reference sample fluids were collected from two different wells with different asphaltene and methane (C1) contents. The reliability of the new asphaltene laboratory results was increased by applying multiple data interpretation. Thus, the difference between the past and recent results can be attributed to fluid alteration with time. On the basis of the analysis in this study, the risk rating was updated to slightly higher than in the previous evaluation, emphasizing the importance of regular monitoring of asphaltene risks.
This study provides valuable findings of time-lapse evaluation of asphaltene-precipitation risks for a reservoir under gas injection. The evaluations currently conducted in the industry are snapshots of instantaneous risks. Through the entire field life, the risks have varied depending on the operating conditions. This study demonstrates that risk estimates can change in a unique field with identical work flow by analyzing data collected at different times. Finally, this study demonstrates the importance of time-dependent reservoir-fluid properties.
Mou, Jianye (China University of Petroleum Beijing, State Key Laboratory of Petroleum Resources and Prospecting) | Yu, Xiaoshan (Sichuan-to-East Natural Gas Transmission Pipeline Branch Company of SINOPEC) | Wang, Lei (China University of Petroleum Beijing) | Zhang, Shicheng (China University of Petroleum) | Ma, Xinfang (China University of Petroleum Beijing) | Lyu, Xinrun (China University of Petroleum Beijing)
Natural fractures have significant influence on flow fields, thus affecting wormhole pattern in acidizing. This paper summarizes our research on wormholing behavior in naturally fractured carbonates. First, statistical natural-fracture models are established using the Monte Carlo method. Second, a two-scale continuum wormhole model is established to simulate wormhole propagation with natural fractures. Finally, extensive numerical simulation is conducted to investigate wormhole behavior and the effect of the natural-fracture parameters on wormhole pattern. In addition, possible wormhole-penetration distance is discussed. This study provides a theoretical basis for matrix-acidizing designs in naturally fractured carbonates.
Wehunt, C. Dean (Chevron North America Exploration and Production Company) | Lattimer, Stefan K. K. (Chevron Europe, Eurasia, and Middle East Exploration and Production Company) | McDuff, Darren R. (Chevron Energy Technology Company)
In this paper, we provide an update on recent advances for and summarize global experiences with dendritic-acidizing (DA) methods, or acid tunneling. We include both coiled-tubing (CT) deployed methods and non-CT methods, and discuss process limitations, candidate-selection criteria, job-design factors, operational learnings, risks, and surveillance requirements and opportunities. A comprehensive review of published information is provided for three different tunneling methods along with relevant information for several other tunneling methods. This literature information is supplemented by depth, temperature, and pressure records for the three processes, which are discussed in detail. Execution factors such as logistics required, length of time required, and volumes of acid and other fluids used are also compared for the three methods.
Previous papers have focused on only one of the methods, whereas we will discuss acid-job optimization, process risks, and surveillance requirements for multiple acid-tunneling methods in substantially greater depth than have past authors. The three methods detailed in this paper are all viable but may have different niches. Differences in the job counts for the different methods are easily explained by differences in process vintages, execution speeds, and depth limitations. Previous optimization efforts were focused on tunnel creation but not acid-job effectiveness in terms of the wormholes generated adjacent to the tunnels; however, some progress is now being made in that regard. There are differences in the processes regarding pushing or pulling the jetting nozzles into the tunnels, and differences in resulting tunnel trajectories. Prejob caliper data are more critical for one of the processes than for the others, and there are significant differences in ability to measure or control tunnel direction. The tunneling tools have different sizes, but when toolsize alternatives are available, the larger tool sizes offer no clear advantages to the operator. Useful risk-mitigation measures are also discussed, and a comprehensive bibliography is included to facilitate further examination of the technology alternatives by other petroleum-industry professionals.
A hydraulic jet pump with both gas and liquid phases at the intake is modeled analytically. A complete system model results when this is combined with models of the surface pump, tubing, casing, and the pressure/temperature behavior of oil and gas. This model is used to size jet pumps before installation and to optimize production. Production optimization includes first estimating the pump-intake pressure and then determining the drive frequency for the surface pump that minimizes the pump-intake pressure. There is an optimal frequency at which the intake pressure is minimized and production is maximized.