Saini, D. (California State University) | Wright, J. (California State University) | Mantas, M. (California State University) | Mezei, T. (California State University) | Gomes, C. (California State University) | Shetty, S. (California State University) | Sirajuddin, M. (University of Southern California)
Over the last thirty years, technology used to produce hydrocarbons has grown exponentially. With the optimization and combination of technologies such as horizontal drilling and hydraulic fracturing, the ability to produce low-permeability or tight hydrocarbon-bearing rocks (shale formations) which were once deemed economically impractical has now become a reality. However, these technologies which have made hydrocarbon production from unconventional reservoir possible have not been implemented in California's Monterey Shale Formation for its wide scale exploitation. Also, due to the relatively short time period of these technological advancements, there seems to be limited research that provides a comprehensive comparison of these three major U.S. analogous shale plays (i.e. Bakken, Eagle Ford, and Monterey) for gaining better understanding on their potential use in future exploitation of Monterey Formation.
First, using publically available data, a comparison of key geological characteristics, completion techniques, and production behaviors of Bakken, Eagle Ford, and Monterey shale plays is presented. Monterey shale is very young and geologically heterogeneous compared to Eagle Ford and Bakken but holds significantly more reserves. Compared to Bakken and Eagle Ford, oil viscosity in Monterey shale is significantly higher and one can also notice that Monterey oil production has declined over the years. Monterey shale has a field dependent completion (pattern spacing and fracturing stage) strategy.
Second, the similar analysis is expended to three Monterey specific oil fields (M, N, and R) that are located in the San Joaquin basin (SJB) of California. A detailed diagnosis of the production behaviors of both the horizontal hydraulically fractured and horizontal non-fractured wells present in the R Field shows that actually non-fractured horizontal wells are more productive which reinforce the needs of a new completion as well as new enhanced recovery strategies that could assist in future development of California's Monterey shale resource while complying with the toughest hydraulic fracturing regulations in the nation.
Though water use per hydraulic fracturing job is relatively low, nearly all fracturing water use in California is in regions of extremely high water stress. The potential use of oilfield-produced water for preparing fracturing fluid formulations can also assist industry in unlocking the potential of Monterey shale without putting burden on precious fresh water resources of the region.
This paper presents the design, current status and future expansion plan of the waterflood scheme in the Girouxville East Lower Triassic Montney reservoir, which is located about 350km north-west of the city of Edmonton, Alberta, Canada (
A small water injection pilot was initiated in October 2013 with a single water injector to alleviate reservoir pressure depletion in the local area. The results were encouraging, and the project has been expanded to a larger scale waterflood scheme in 2015, which currently consists of 6 horizontal producers and 4 horizontal water injectors. A 388 ha (1½ sections) waterflood expansion was designed based on comprehensive geological and engineering evaluations. A detailed geomodel was created with available core data, well petrophysical analyses, horizontal well geologic descriptions and seismic data in the area; the Montney formation was subdivided into 4 coarsening-upward cycles, with 6 facies identified within. Dynamic reservoir simulation was initiated by importing data from the geomodel. Reservoir and well properties were fine-tuned with a high-quality history. Multiple forecast scenarios were run to determine an optimal waterflood recovery scheme.
Within half a year most offsetting oil producers have shown positive response to water injection with an increase in total fluid and gradual decrease in the producing gas-oil ratio (GOR). The oil rate decline has slowed down significantly with anticipated incremental oil recovery of 5 – 7% OOIP over the primary depletion. Further expansion has been identified in the oil-leg of the surrounding sections. The waterflood design will focus on down-dip injection to maintain more gravity stable injection water fronts along the field oil-water contacts for optimum pressure support and oil displacement.
Transportation of solids in form of slurries has become one of the most important unit operations in industries across several disciplines. In fact, the need is more pronounced in industries that are very important for human survival such as food processing, pharmaceuticals and energy (coal, oil and gas). A lot of work has been done in the past 30 years in understanding the factors affecting the deposition velocity of solids in slurries. Experimental observation and theoretical predictions pointed to mixture velocity and solid/fluid properties especially rheology of the resulting slurry to be the most important factors that dramatically affect particle motion and patterning.
This paper presents a critical deposition velocity model and a "stability flow map" for complex rheology slurries. The critical deposition model utilizes a more robust generalized 2-parameter rheology model to account for any given slurry rheology. The "stability flow map" demarcates the different flow patterns that may be observed at different mixture velocity and rheology. On this map, the homogeneous slurries are predicted at low rheology and high mixture velocity whereas heterogeneous slurries (with a concentration gradient) predicted at high rheology (yield stress effects).
Sensitivity analysis was conducted on critical Reynolds number, particle density, carrier fluid density, generalized flow behavior index, and pipe diameter. It was observed that increase in shear thinning behavior, particle density, pipe diameter, and particle diameter led to a decrease in the laminar region and an increased unstable region. The model showed good performance when tested on glass and stainless steel beads test data available in open literature. The model was tested on hydrate slurries generated with additives at The University of Tulsa and the flow regime predictions were in good agreement with observations.
Preliminary simulation with this map may help engineers select flowline size and carrier fluid rheology for a given type of solid particle.
Goudarzi, Ali (The University of Texas at Austin) | Alhuraishawy, Ali (Missouri University of Science and Technology) | Taksaudom, Pongpak (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Bai, Baojun (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Delshad, Mojdeh (The University of Texas at Austin)
Conformance control has long been a compelling subject in improving waterflood oil recovery. By blocking the areas previously swept by water, subsequently injected water is allowed to access the remaining unswept portions of the reservoir and thereby increase the ultimate oil recovery. One technique that has recently received a great deal of attention in achieving the so-called "in-depth water shut-off' is preformed gel injection. However, processing and predicting the performance of these gels in complex petroleum reservoirs is extremely challenging. As target reservoirs for gel treatments are mainly those with fractures or ultra-high permeability streaks, the ability to model the propagation of gels through a fractured reservoir was considered as a new challenge for this research study.
The primary objectives of this work are to conduct laboratory work to understand the transport and propagation of microgel through fractures and develop conformance control schemes using a reservoir simulator to help in screening oil reservoir targets for effective particle gel applications to improve sweep efficiency and reduce the water production. Fractured experiments using transparent apparatus were performed to observe gel transport in matrix and fractures. The same set up was used to observe the effects of gel strength, gel particle size, and fracture size on gel transport. Numerical simulation of fluid-flow in fractured reservoirs can be computationally difficult and time consuming due to the large contrast between matrix and fracture permeabilities and the extremely small fracture apertures and the need for using unstructured gridding. In this work, a model that accurately represents the complex reservoir features, chemical properties, and displacement mechanisms is developed.
The five-spot transparent fracture experiments allowed us to identify the transport mechanisms of microgels through fractures-conduits and also the control variables. With an integration of comprehensive gel transport modules and a novel Embedded Discrete Fracture Modeling (EDFM), gel rheological and transport properties of shear thinning viscosity, adsorption, resistance factors, and residual resistance factor, using multiple sets of fractures with dip angles and orientations were captured. The models were validated against lab measurements and implemented into a reservoir simulator called UTGEL.
The mechanistic models and numerical tool developed will help to select future conformance control candidates for a given field and to optimize the gel chemistry and treatment.
The increase in wastewater disposal associated with hydraulic fracturing, and other subsurface fluid injection and production (SFIP) operations as well as the heightened public concern regarding possible induced seismicity, have propelled us to study the related issues. In this work, we investigate induced seismicity caused by pore-pressure changes due to fluid injection. We use a reservoir simulator to model the pore-pressure change in a realistic case with different injection and production scenarios. This research shows that the presence of critical faults and the net injected volume are among the most important risk factors contributing to induced seismicity. Reservoir characteristics such as geometry, size, and permeability are identified as the main components that pertain to reservoir pressure response, causing critical pore-pressure increase and subsequent potential seismicity. We apply our method to the Central Illinois Basin, which is a primary candidate for CO2 Sequestration, and observe that the pressure changes differ widely, but can easily lead to fault instability and seismic activity up to 10 km away from the injection well. The magnitude of pressure increase and the geometry of the affected area greatly depends upon the permeability structure of the injection formation and surroundings. Further, we define the required pore-pressure buildup for fault instability. In addition, we generate a random distribution of faults in the area of interest where they have a certain distribution for required pore-pressure buildup for fault slip (criticality). Earthquake magnitudes are sampled from a distribution following Guttenberg-Richter law. We introduce a simple homogeneous, isotropic representation for the reservoir in order to study the primary parameters that affect the frequency and magnitude of induced seismic events. Given the absence of a physics-based method for induced seismicity risk assessment, this paper proposes a novel approach for said risk assessment, and can be used to mitigate the fault reactivation risk.
This paper describes an approach to design the well clean-up operations by modelling the process with transient simulator. The paper will discuss the challenges with well clean-up with high volume of invaded fluid and a solution for efficient clean-up honoring all flowing and flaring limitation constraints in an environmentally sensitive area.
Wellbore model was built in a software allowing a transient wellbore and near wellbore simulation during drilling and clean-up operations. It allowed to understand such a highly dynamic process by analyzing the evolution of rate, pressure and composition versus time.
This technique was applied for a field where one may face challenges during the well clean-up such as well loading up with heavy fluid and high back pressure from production line. Moreover, according to government regulations flaring during production phase should be minimized as much as possible which creates another constraints with clean-up operations associated with flaring.
A detailed model of clean-up dynamics allowed a radical change of well clean-up planning. A number of scenarios are evaluated in terms of uncertainty and risk and a detailed operating procedure is developed for the optimized well start-ups. Unlplanned emergency shut-down at surface is also simulated to ensure safety and restart possibilities, within the regulatory constraints imposed locally. With the confidence that the models are representative after sensitivity studies, it provides the operator with a tool to test sensitivity cases and develop operational solutions. It is then possible to suggest the most efficient process and estimate the volume of gas to be flared in a worst case scenario, an essential information to apply for flaring permission to the government.
This approach is novel, and is possible through the utilization of a dynamic transient wellbore model with a near wellbore reservoir model that takes in consideration the invasion/losses and subsequent recovery of permeability during the clean-up process (
Fluid properties are often one of the key uncertainties in reservoir simulation studies. A workflow and guidelines are presented to develop an overall probabilistic forecasting framework, through which likely fluid models are validated, uncertainty ranges are estimated, and probabilistic PVT models are generated for use in stochastic black oil reservoir simulation modeling.
Workflows are provided for two distinct scenarios. For scenarios with a large number of samples from the reservoir or a representative analog fluid property database, standard statistical methodologies are applied to generate probabilistic fluid models. However, in most cases where there are only limited data available, a unique approach is adopted to generate a representative pseudo-database for uncertainty assessment workflows. The pseudo-database is generated based on fluid property correlations that are screened for the conditions of the specific fluid system. The pseudo-database is used to both validate a reliable likely case and to determine ranges to generate probabilistic models. Numerical formulations of probabilistic models are provided.
Application of the workflow is demonstrated for three different cases of fluid property data. For a case based on a large set of PVT measurements, standard deviation of specific fluid properties (FVF, GOR, Viscosity, and Compressibility) is calculated and used in standard statistical methods to calculate P10/P90 cases. In another example, the validity of fluid viscosity data based on an assumed viscosity correlation was investigated, suggesting that fluid viscosity was actually closer to a P20 model as opposed to a P50 (likely case). In another case study, where only limited PVT data were available, a number of screened/filtered fluid property correlations are used to represent available PVT data, and then the input parameters are perturbed to generate a pseudo-database to capture fluid property ranges as well as variation in a field.
Currently, there is a lack of a systematic way to determine uncertainty ranges for fluid properties, as well as validating the most likely case (best case or mid case). The novelty of our framework is in the provision of a consistent workflow to generate probabilistic fluid models that are not based on experiential methods employed in the past.
This paper presents a simple method for the removal of tidal effects based on analysis of the primary derivative of pressure. The method consists of isolating the oscillating component of the primary derivative caused by tidal effects. This is possible because the primary derivative of the reservoir component approaches zero with time while that of the tidal component persists due to its oscillatory nature. The isolated derivative of the tidal component of pressure can be fitted to a reference tidal signal or a combination of harmonic functions. Once this is done, the derivative tidal component function can be filtered out from the pressure derivative and pressure signals for transient analysis.
The method is validated by analysis of synthetic data where a sinusoidal signal is added to a test and the method is used to extract it from the combined signal and then compared to the input signal. Application of the method to an actual well test is also presented. This approach can be used to complement other published methods referenced in the paper, but contrary to those, it does not require to guess the shape of the reservoir pressure component before removal of the tidal component.
Patri, Om P. (University of Southern California) | Tehrani, Arash S. (University of Southern California) | Prasanna, Viktor K. (University of Southern California) | Kannan, Rajgopal (University of Southern California) | Panangadan, Anand (California State University Fullerton) | Reyna, Nabor (Chevron Information Technology Company)
Gas compressor failures are frequently caused by breakdown of valves. Since production is dependent on rotating equipment, it is useful to minimize downtime caused by such valve failures, and try to predict them in advance. This is a challenging problem, which we address using Big Data analysis of the data gathered by a large number of sensors deployed on various parts of the compressor. These sensors take periodic readings (at every few minutes) of various physical properties of the compressors including motor winding temperatures, compressor vibrations, and pressure and temperature for both suction and discharge at various compression stages. We frame this problem as a multivariate time series classification task, and propose a novel machine learning approach to solve it.
Our proposed approach is based on the concept of shapelets, which are discriminative subsequences extracted from time series. This approach does not make assumptions about the nature of the dataset (crucial for real industrial datasets) and has very fast classification times. These shapelets act as a ‘signature’ capturing the characteristics and differences between sensor data related to normal valve function versus failed valve function. Shapelets are increasingly being used for univariate (single dimension data read by one sensor) time series data mining. But there have been few efforts to solve the problem of multivariate time series classification using shapelets due to the additional challenges emanating from multiple sensors in terms of the size and variety of data. Specifically, the existing approaches make the assumption that the reading of sensors are independent, which is not the case for sensor data in gas compressors as variation or anomaly in a valve affect the reading of adjacent sensors. Since all the sensors record data synchronized in time, the temporal dependencies across them need to be captured.
In this work, we propose a method, which attempts to incorporate these dependencies into the final shapelet-based classification framework. We achieve this using a heuristic of inter-leaving time series data across the sensors. This helps us reduce the multivariate time series data to a univariate format such that existing univariate shapelet extraction methods can be applied directly on the data. We evaluate our approach on real sensor data taken from gas compressors in an oil field in North America. Our results illustrate that time series approaches based on shapelet mining are valuable for fast prediction of failures from sensor data in oil and gas fields. These approaches provide key insights into the functioning of the individual sensors as well as deliver a visual aid to domain experts for further root cause analysis.
Viscoelastic surfactants (VES) have been used to replace polymer-based fluids as effective, cleaner, and non-damaging viscofying carriers in frac-packing, acid fracturing, and matrix acidizing. However, several limitations challenge the use of VES-based fluids including: thermal instability, incompatibility with alcohol-based corrosion inhibitor, and intolerance to the presence of contaminating iron. This work introduces a new VES-based acid system for diversion in matrix acidizing that exhibits excellent thermal stability and diversion performance in both low-and high-temperature conditions.
Rheology measurements were conducted on spent VES-acid system as a function of temperature (77- 300°F) at a pH of 4-5. The effect of acidizing additives on the VES viscosity was investigated. The additives included a corrosion inhibitor, non-emulsifier, iron-chelating agent, and iron-reducing agent. Single and dual coreflood experiments were performed using limestone core samples with an initial permeability range of 4-200 md and a permeability contrast of 1.5-55. Post CT-scan imaging was conducted to investigate the wormhole topography. The diversion characteristic of the new VES in the dual coreflood experiments was evaluated by the structure and the extent of wormhole propagation in the low-permeability core.
Rheological data for 15 wt% HCl spent VES-solutions showed a maximum viscosity of 200-800 over a temperature range of 150-170°F, depending on the VES concentration in the sample. Without acidizing additives, a minimum of 50 cP was obtained at 195, 230, 250, and 275°F at 4, 5, 6, and 8 vol% of the VES in solution, respectively. None of the tested acidizing additives had a negative impact on the VES viscosity. At 8% VES loading, the acidizing package was optimized such that a minimum of 75 cP was obtained at 300°F.
Dual coreflood experiments were conducted at 150 and 250°F, and the results proved the ability of the proposed VES to divert efficiently in limestone formations. Single coreflood experiments also confirmed these results. Coreflood data indicated that a range of permeability contrast of 4-10 is the optimum for diversion ability in terms of the final permeability enhancement of the low-permeability cores. The results revealed 18.6, 45.6, 82%, and infinity when the permeability contrast was 28.3, 14.4, 6. 3, 1.63, respectively. A dual coreflood experiment was conducted for two cores with a permeability contrast of 1.6 at 150°F. The VES-acid system in the presence of all acidizing additives exhibited divergent performance that exceeded the performance of the VES in the absence of additivies. These results prove the stable performance of the VES and the enhancement in viscosity response after addition of both the iron-control agent and the non-emulsfier, which resulted in less acid leakoff and better wormhole structure.