Using planar fracture models to match treatment pressure and improve understanding of the fracture geometry generation is not a new concept. Knowledge gained from this exercise has historically been used to improve engineered fracture completions and production, and maximize net present value (NPV); however, at some point during the progression from vertical to horizontal wellbores, many within the industry have forgotten about the learnings that can still be gained from current fracture models. Engineered completions have been largely replaced by spreadsheet efficiencies relevant to operations rather than production in too many cases. Some images of unconventional well stimulation treatments portray fractures growing in every direction, forming patterns that resemble shattered windshields, and have often excluded the known physics related to rock geomechanics, reservoir properties, and geology. Excuses to dismiss modeling are numerous and are gaining the reasoning of conformists.
Unconventional resource plays might or might not contain large numbers of natural fractures; but, current fracture models can still be used to gain insight into the fracture geometries being generated. While the development of complex fracture models continues to evolve, the industry can still gain insight to fracture geometry and resulting production using current planar fracture modeling. Caveats to this process are that it requires: Valid measured data to establish model constraints. The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model. The engineer to understand which "knobs" should be used based on real diagnostics information. The actual single well production to be an integral part of the process.
Valid measured data to establish model constraints.
The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model.
The engineer to understand which "knobs" should be used based on real diagnostics information.
The actual single well production to be an integral part of the process.
This paper demonstrates the results of honoring data measurements from a multitude of potential sources, including downhole microseismic data, downhole deformation tiltmeters, offset pressure monitoring, DTS, DAS, diagnostic fracture injection test (DFIT) analysis, injection as well as production data with bottomhole pressure measurements, etc., and the resulting observations and conclusions. Several industry examples are discussed to help frame the vast amount of information possible to help engineers do a better job of including more diagnostics into routine operations to provide additional insight and ultimately result in improved models and completion designs.
This paper is not intended to merely demonstrate the results of the work but to spark an interest in bringing more intense engineering back to fracture stimulation modeling for horizontal completions.
Jaiswal, Aaditi (University of Southern California) | Alabdulbaqi, Nibras (University of Southern California) | Alsafar, Ali (University of Southern California) | Ershaghi, I. (University of Southern California)
While in reality production from unconventional reservoirs with nanoscale pores and complex systems has caused a dramatic increase in oil and gas production, little is known about an effective characterization let alone prediction of long-term performance of individual wells. These systems challenge our classical understanding of petroleum reservoirs developed over decades. In the meantime, and the absence of a full understanding of the source rock systems, some practitioners have resorted to using reservoir engineering tools and techniques for production forecasting from source rocks. These toots borrowed from engineering principles of conventional petroleum reservoirs do not include the peculiar nature of the source rock systems. This, of course, is a long stretch going from applying conceptual models for uniform pore space occupied by hydrocarbons and water, to systems where fractures, microfractures, present significant complications to understanding the physics of the flow in source rocks. In summary, the realm of producing from source rock is one of those examples where before a better understanding of the rock physics is developed, already in different play areas, we have witnessed the phenomenal growth of drilling and completion of thousands of wells over the last decade.
Forecasting EUR (estimated ultimate Recovery) for individual wells producing from source rocks are essential in decision making at all levels. This is quite challenging particularly when only a few months of production data are available to predict the future. An urgent need in the industry has been using rapid methods for estimation of EUR's in the early life of any new well. These estimates have critical economic viability for business success and economic survival. To stay competitive and to provide attractive rates of return, companies prefer to drill in areas with the highest EUR's per well.
Among the techniques in widespread use are the decline curves. These simple regression models are used to estimate up-front guidance regarding total recoverable volumes over a long period. In practice, any forecasting can help to establish the resource base for individual wells and the entire asset. But the question is the validity of such forecasts. Decline curve analysis is based on empirical observations of production decline. In using decline curves, we assume that reservoir conditions and operating conditions causing the historical decline continue unchanged during the forecast period. In this study, we include well production with 5 or more years of history and examine various decline models using the early history data to test the estimated performance vs. the actual performance. We have noted serious limitations on the use of such models.
Bond, Andy (Caelus Energy Alaska) | Jasser, Rami (Caelus Energy Alaska) | Johnson, Vern (Caelus Energy Alaska) | Morgan, Mike (Caelus Energy Alaska) | Martin, Mike (Northern Solutions) | Palisch, Terry (CARBO Ceramics) | Williams, Brock (Resman)
The Oooguruk Unit is on a man-made gravel island in the Beaufort Sea, five miles offshore the Alaskan North Slope (ANS) in Harrison Bay. The field produces from the Kuparuk, Torok, and Nuiqsut reservoirs. The focus of this paper is the Nuiqsut sandstone, which is currently undergoing water and lean-gas injection for secondary recovery. The wells are completed as 6,000- to 7,000-ft horizontal laterals aligned parallel with the preferred fracture orientation in a line-drive waterflood pattern. Recent optimizations in mechanical-diversion fracturing in these laterals have provided significant improvements in production rates, including several recent wells with initial production of more than 7,000 BOPD. This paper will document the completion and fracturing-design evolution over several vintages of wells, as well as the use of preinstalled tracer systems to verify production uniformity and diversion success.
The reservoir ranges in thickness from 60 to 120 ft and is divided into several producing sand and shale intervals. The initial phase (I) of completions planned for this reservoir was to use 8,000-ft-long undulating openhole horizontal laterals. However, these were quickly abandoned after the first well collapsed in a shale section. The second phase (II) used undulating wellbores for producing wells, but were completed with preperforated pups spaced evenly throughout the uncemented liner in the horizontal section. These wells were also stimulated with dynamic-diversion fracturing treatments that used ball sealers. Because of the logistical difficulties and expense in fracturing operations on a gravel island in the Beaufort Sea, two wells were also completed during this phase as unfractured dual-laterals, but resulted in productivity similar to dynamic diversion fracturing in one well and significantly less in the second well. During these phases of increased well productivity, modifications were required to increase waterflood well injectivity, which was accomplished by implementing a system of high-pressure breakdown (HPBD) stimulations, as well as fully mechanical diversion-fracture treatments. These changes in injection-well completions will also be described in the paper.
Phase II wells resulted in production improvements of nearly 100% over the Phase I completions. This led to the third phase of development, which used mechanical-diversion techniques, implemented in relatively flat horizontal laterals. This completion type allowed mechanical-diversion fracturing treatments that placed more than three times the low-density ceramic (LDC) proppant and generated wells with initial production of more than 7,000 BOPD (an additional 100% increase over Phase II completions). All future producing wells are now planned to be completed with mechanical-diversion equipment. The completion-optimization evolution described in this paper will be useful to completion and development engineers of other conventional reservoirs, and the lessons learned are already being successfully applied to another nearby ANS development.
Unconventional reservoirs require extensive hydraulic-fracturing treatments to produce fluids economically and efficiently. The main purpose of such treatments is to create complex fracture networks with high-conductivity paths deeper into the nonstimulated reservoir regions. Proppants play an important role in maintaining good-quality fracture conductivities, which then greatly affect long-term production performance. In addition, research on proppants has shown a reduction in conductivities under downhole stresses and multiphase-flow behaviours. Therefore, it is important to study the effect different proppants and conductivities have on production performance through actual field cases.
To evaluate the production performance of wells completed with different proppants, the authors proposed an integrated work flow for characterization and simulation of unconventional reservoirs. This work flow is unique because of the stochastic fracture-network-generation algorithms and improved unstructured-grid-generation techniques. Both analysis of field-production data and numerical simulations were performed on eight wells in the CAPA field of North Dakota. For the field-data analysis, three public-data resources were reviewed to prepare a summary of reservoir properties, fracture properties, proppant properties, and production history. For the numerical simulations, all the wells were modelled and simulated with the proposed work flow. Finally, sensitivity analyses were carried out to investigate the effects of fracture conductivities and natural fractures.
After completing the field-case studies and reservoir simulations, it was concluded that with the same fracture design, higher fracture conductivity improves production performance. Pumping a smaller volume of upgraded proppants with higher conductivity not only improves long-term production performance, but also justifies the additional costs and reduces the overall operation time of the entire hydraulic-fracturing job. The stimulated reservoir volume was greatly increased, as was the production performance, where natural fractures exist.
In this paper, field-data analysis was applied in the Bakken to demonstrate the integrated unconventional work flow. The proposed unstructured-gridding algorithms can be incorporated into any preprocessor to handle complex networks. Reservoir, fracture, and proppant characterization and reservoir simulation of the field cases can help engineers prepare and interpret simulation input and output.
The inherent complexity of unconventional resources, within the ever growing economic development of these, gave rise to many work-flows, in which both natural and hydraulic fractures are accounted for through the use of DFN (Discrete Fracture Network) models. Assessing the specific role of fractures in a multiphase flow context while inferring their mechanical behavior as well as their interaction leads to a better understanding of production characteristics from shale and tight reservoir.
A realistic reservoir case was considered for this study. A classical characterization methodology was used, integrating different scales, from seismic to core analysis. This characterization step, along with geomechanical considerations, such as brittleness leads to a statistical description of two fracture sets (natural and hydraulic), building a continuous DFN. This makes up our fracture model, geo-stochastically controlled. A simplified coupling method, for which two distinct mechanical laws (plastic-elastic) are applied, is used to describe the hydraulic fracturing process. Hydraulic fluid injection is simulated using an approximate fluid model (PAD + ‘Proppant’). Accounting for the pressure dependent fracture compressibility involves the inclusion of the dynamic behavior of fractures into the DDFN through the use of analytic and empirical fracture deformation models.
The history-match of the BHP recorded during the stimulation and overall microseismic cloud, honors hydraulic fracturing characteristics such as injection rates and fluid properties, hence allowing the validation of both the characterization and geomechanical hypothesis formulated. This calibration was carried out on each hydraulically fractured stage, followed by an integration to the reservoir fluid flow simulator.
This paper describes a new method, called DDFN (Discrete and Deformable Fracture Network), applied at a large reservoir scale. The reservoir discretization method is computationally efficient, making it appropriate for any optimization of the hydraulic fracturing process. An additional characteristic of the DDFN approach is the by-passing of the up-scaling step, since the DDFN is included at the reservoir simulation scale directly, in the form of an unstructured grid, thus providing a more realistic representation of the overall fracture geometry. Examples of such simulation results performed using realistic data are shown. Discussion of the worth and limitations of the method is done.
The application of this method to all stages makes up a realistic method, which could be used at reasonable speeds within any reservoir study. The main advantage of such a method is that it can be adapted to any characterization method. By nature modular, it could be linked to any workflow which provides a continuous fracture network made up of the interaction between natural and hydraulically induced fractures
Various analytical and numerical models have been proposed to predict production performance of hydraulic fractured wells and to investigate the effect of fracture geometry and fracture conductivity on well performance. These completion design parameters greatly impact E&P operators' return on investment (ROI). In this study, we conducted numerous field case studies in the Bakken formation to compare production performance of hydraulic fractured wells with different completion designs. Since all wells are located in the same field, the geological difference was considerably minimized. The wells were grouped and analyzed by different completion and stimulation design parameters. Specific grouped categories included percentage of upgraded proppant in the total proppant amount, lateral length, number of stages, etc.
We then simulated post-fracturing production performance of these fractured wells. An advanced meshing technique was developed to honor complex fracture networks with unstructured Voronoi grids. We applied this technique to investigate the characteristics of hydraulic fractures such as fracture conductivity, aperture and permeability distribution on the long-term production of the wells. Core data and well logs were analyzed for reservoir characterization. Several assumptions were made to estimate pumped fracture width, stress-dependent fracture permeability and stimulated reservoir volume. Finally, sensitivity studies were performed to investigate the effect of fracture conductivity on production performance due to superior vs. low-quality proppants.
The objective of this study was to determine if upgrading completion designs to high quality proppant materials would achieve better fracture conductivities and long-term production performance. After all well data was analyzed and the production related parameters were summarized, it was determined that upgrading the completion designs with higher quality proppants provided dramatically improved production rates.
The following unstructured mesh generation algorithms successfully implemented the local grid refinement feature around fractures, which can handle non-orthogonal fractures and more complex fracture geometries. The final simulation runs and sensitivity studies further demonstrated the importance of both stimulated reservoir volume and fracture conductivities. The same long-term production performance was also predicted by using reduced amounts of upgraded proppant with improved fracture conductivities.
Despite being penetrated by over 100 wells, and more than a century of studies, the in-place and recoverable volumes of oil resources within Nigeria's bituminous belt are still inconclusive. Noteworthy is the misleading appropriation of "reserves?? to the deposit. While there is an obvious motivation to improve the current situation, credibility requires that such efforts are premised on a combination of reliable dataset and robust method of study.
This article is an attempt at reconciling and improving current estimates of the hydrocarbon potentials of the Nigerian bituminous belt. It reviews and integrates numerous datasets on the belt. Reasonable assumptions, empirical correlations and analogue information are used to mitigate identified data gaps while recognising uncertainties. With estimated input data and associated uncertainties, deterministic and probabilistic techniques are employed for robust volumetrics. Unlike previous studies, we consider solution gas.
Using performances of some proven exploitation technologies in provinces of comparable reservoir and fluid characteristics as Nigeria's, we make reasonable estimates of recovery factors, and establish cumulative distribution curves for recoverable (not reserves) volumes of discovered bitumen, heavy oil and oil shale deposits, including the dissolved gas content.
From the analyses, we estimate 71, 207 and 415 billion barrels as the P90, P50 and P10 stock-tank oil in-place volumes, respectively. Corresponding solution-gas quantities are 1.4, 5.0, and 13.6 Tscf, respectively. Compared to current official record of about 43 billion barrels, which does not account for the field-proven solution gas, potentials of Nigeria's bituminous belt may be significantly underestimated at present. Although the volumetric ranges in this study reflect the relative magnitude and impact of uncertainties, sensitivity analysis indicates that reservoir extent and thickness as well as solution gas-oil ratio are the main uncertainties. Consequently, a key objective of future appraisal programs should be to narrow the current range of (static) uncertainties.
The activities performed on seismic operations generate environmental impacts either during base camp installation or line operations; this generated the need to implement alternative measures or control methods to reduce the agents which contribute to such impacts. This study is focused on the base camps, because according to statistics from our projects in Bolivia, that's where the majority of organic solid waste is generated.
Following this, came the idea of recycling the organic solid waste, based on methods to obtain a sustainable benefit.
Implementation and application of Earthworm culture at Base Camp from to obtain organic fertilizer Closed Waste Management Cycle by cultivation areas at base using fertilizer produced by organic transformation with the resulting production of vegetables and fruit.
Closed Waste Management Cycle by the implementation of forest seedlings employing organic fertilizer from Earthworm culture.
This way we perform the daily routine to mitigate the environmental negative impacts that may be generated by base Camps: through low cost implementation methods and easy operation.
The environmental monitoring from generation of organic solid waste until its recycling represents the closing of the Waste Management Cycle at Base Camp and it is a component of the best environmental practices in which all Project workforce can participate.