Hooshmandkoochi, Ali (Seven Generations Energy Ltd.) | Shirkavand, Farid (Seven Generations Energy Ltd.) | Prokopchuk, Richard (Canamera Coring) | Osayande, Nadine (Weatherford) | Yousefi Sadat, Ali (Weatherford) | Minhas, Arminder (Halliburton)
One of the most important hydrocarbon resources in the Western Canadian Sedimentary Basin (WCSB) is the Montney tight shale formation, which extends approximately 55,000 square miles from northeast British Columbia to northwest Alberta. Operations in the Alberta deep-basin Montney have proven this area to be one of the continent's most productive unconventional resource plays. As part of the field development plans, cores are cut from the reservoir rock to directly measure source rock properties through analysis of core samples and calibrating wireline logs with data extracted from the core samples.
The subsurface geology of the upper hole section in this particular area is complex, where reactive, swelling, and fissile shale as well as coal beds and lost-circulation zones extend across 2700 m of the openhole section. As such, historically in this field, the Montney has been cored using a weighted oil base system incorporating water contamination into the core; if zero water contamination is mandated, casing is run into the reservoir ahead of the coring section to allow coring with base oil, which leads to smaller core sizes. Additionally, coring operations can require several days when conventional coring technology is applied because of the multitude of necessary trips into and out of the hole.
Well engineers applied a systematic approach to achieve new targets by incorporating the latest available technologies and drilling techniques in the industry into a coring program while also optimizing well structural designs by minimizing use of casing strings. This allowed achieving the project's primary objectives of cutting larger-sized cores with no water contamination using minimal planned trips.
This paper discusses how managed pressure drilling (MPD) and wellbore strengthening techniques, as well as new coring technologies, were analyzed, planned, and incorporated into this project. This led to the successful execution of an optimized, cost-efficient well structural design with 100% core recovery and no water contamination while. At the same time, a new record was set in terms of the longest core length cut in one run in onshore North America.
Porosity can be obtained from drilling data by using different correlations that relate the porosity to the unconfined compressive strength (UCS), which is obtained from drill bit inverted rate of penetration (ROP) models. Knowing the porosity at a given depth can benefit in helping to define the formations being penetrated and to characterize variations in a reservoir, thereby benefitting in selective stimulation. In this paper, previous studies that present methods for calculating porosity from UCS values will be compared and evaluated with sections of porosity that have been calculated from log data taken from three wells in Alberta, Canada. The correlations that will be compared include: Onyia, Sarda, Erfourth, and the UCS-gamma ray methods. The Onyia, Sarda, and Erfourth correlations are previously published while the UCS-gamma ray method correlates UCS in conjunction with the gamma ray at the bit. The porosity values that are found through these correlations are then plotted and their trends compared to each other as well as to the porosity obtained from log data in different sections from the well in Alberta, Canada. This process will help to determine what formation types are best correlated to the individual correlation. Typical drilling data is used in an inverted ROP model to obtain UCS. The UCS and gamma ray values are then taken and related to the porosity through the correlations presented in this paper and compared to the porosity determined from log data. Examining the different correlations that have been analyzed in various types of formations yield information indicating which correlation is best correlated to a specific formation type. The comparison's show that the predictability for some correlations are reasonable for limited datasets and sections of the well. To reasonably predict porosity values for mixed lithologies or shale formations, the integration of gamma log data is necessary. The trends exhibited from the correlations show that the comparison between porosity in shale is better seen when using the integrated UCS-gamma ray correlation. Utilizing the new UCS-gamma ray model seemingly indicates that this useful new method can more accurately predict porosity variations in mixed lithologies and in shale reservoir sections. Bettering stimulation placement as well as minimizing logging in the reservoir can greatly reduce the overall cost of the operation. The improved selective stimulation process could also allow for higher production rates and/or potential reduced stimulation cost, thus increasing overall profit.
The first fracture treatment using crosslinked guar was performed in 1969. Since then, guar and its derivative polymers have dominated hydraulic fracturing. Because of volatility and supply issues with guar gum that have surfaced during peak activity years, the industry has turned to alternatives. One of those alternatives is carboxymethylcellulose (CMC) that, just like guar, comes from the food industry. CMC is also used in pharmaceuticals as a thickening agent and in the oil and gas industry as an ingredient in drilling mud. Use in hydraulic fracturing is surprisingly limited. The objective of this paper is to demonstrate successful cases of CMC-based treatments over traditional guar and surfactant-based treatments used in linear and foamed applications.
This paper presents several cases from treatments performed on formations such as Cardium, Montney, Belly River, and Dunvegan. Presented production comparison will demonstrate that wells treated with CMC-based hydraulic fracturing fluid system yield similar performance when compared to wells treated with guar, its derivatives, and surfactant-based fluid systems.
Cost savings realized when switching to CMC-based fluid systems are also discussed in this paper. Laboratory tests are described, and results are shared to demonstrate the performance of CMC compared to guar, carboxymethylhydroxypropyl guar (CMHPG), and surfactant systems.
The paper attempts to provide a degree of confidence to the operators looking for cleaner alternatives to industry-established fluid systems, and shows that these can be successfully implemented without additional risk or cost.
Aslanyan, Arthur (TGT Oilfield Services) | Aslanyan, Irina (TGT Oilfield Services) | Karantharath, Radhakrishnan (TGT Oilfield Services) | Minakhmetova, Roza (TGT Oilfield Services) | Kohzadi, Hassan (Global New Petro Tec Ltd.) | Ghanavati, Mohsen (Global New Petro Tec Ltd.)
Gas or fluid ingress into the cement channel and then up to the surface through the surface casing annulus is called Surface Casing Vent Flow (SCVF), which causes Sustained Annulus Pressure (SAP) as a common occurrence in the petroleum industry. Gas may also migrate to the surface outside the outermost casing string, which is often referred to as external Gas Migration (GM) or seepage. In some countries with shallow coal reserves, gas migration sometimes occurs in association with coalbed gas (CBG) development. Dewatering the coal seams or lowered water levels in coal, whether induced by drought or by domestic aquifer pumping, can result in the release of methane and other natural gases in coal (NGC). Hydrocarbon gases released into the atmosphere is an environmental concern. More importantly, leaking fluids may contaminate subsurface fresh-water reservoirs, resulting in a major catastrophe for the environment and human population.
According to the latest statistics, 6% of almost 270 000 operating and idle wells analysed in Alberta were found to contain leaks, 5.5% of them having SCVF and 0.5% gas migration [
Even if a well is to be abandoned, the operators must precisely identify the location of the leak and its source to perform a successful plug-and-abandonment (P&A) operation. P&A activities are non-revenue generating activities. The right diagnostic technology is critical for correct leak source identification to eliminate the costs associated with numerous unsuccessful attempts.
The technique of Spectral Noise Logging (SNL) coupled with High Precision Temperature (HPT) Logging have extensively benefited oil industry outside Canada in accurately identifying fluid flow behind multiple casing pipe barriers and in locating leaks and their sources [
An innovative proven new tool, the "Fluid Hammer??, provides axial percussive force and effective weight transfer to the bit which increases the rate of penetration (ROP) from 30-50% with no impact to bit life.
BBJ Tool's patent pending Fluid Hammer together with Suncor Energy Inc. of Calgary, Alberta, Canada has applied the Fluid Hammer in several wellbores with excellent results. The tool is positioned between the bit and the mud motor with an antiback off connection. The relatively simple mechanical design delivers effective agitation to the bottomhole assembly (BHA) and reduces issues in deviated wellbores, such as hole drag and proper weight transfer to the bit. It has been successful in improving ROP in vertical/deviated and horizontal hole sections.
The Fluid Hammer has been successful on >80 bit runs in vertical/deviated/horizontal wellbores with water, oil base and nitrified drilling fluid systems. Direct comparisons of formations with and without the Fluid Hammer have been completed. The study compares geological formations, compressive rock strength, mud weight and BHA parameters such as weight on bit, rpm, hole drag and ROP. Resulting sliding ROP matches rotating ROP in horizontal wellbores with the downhole agitation at the bit. Tool design improvements will be further enhanced with the use of an Axial Dynamic Simulator.
The Fluid Hammer increases ROP, has no effect on telemetry tools, causes no restriction to pump rate and can be used with any mud system. This tool can be run in conjunction with conventional adjustable housings or rotary steerable tools. No special percussion bits are required and it has been run with a wide variety of conventional bit types and sizes. An additional feature of the Fluid Hammer has been in extended reach horizontal hole sections in which the BHA has been simplified with the removal of conventional agitation tools.
Reducing well costs with innovative technology has always been a challenge for drilling engineers. Utilizing correct drilling parameters and procedures can deliver optimum drill rates, but achieving further advancements requires a step change with new technology. This step change taken by Suncor Energy was achieved by adding percussion force to the drilling bit with the Fluid Hammer. This hammer concept has been used in the past with air percussion delivering high ROP's, but never has it been used in conjunction with maximum bit weight, drilling motors and optimum drilling fluid parameters.
This innovative tool provides a wider range of applications to the drilling process with impressive results. The improvement in reduced drilling time has a direct relationship to reduced drilling costs and drives down well costs. The Fluid Hammer is a low risk addition to the drilling BHA and can be used with all bit types. This technology is applicable in all formations as it can be modified to the correct percussion force for different rock compressive strengths.
Fluid Hammer testing, improvements and conclusive results were developed on wells in the Alberta Foothills Panther field. Obtaining good comparable data is essential when testing and perfecting a new tool. The Panther field was an excellent area to obtain and compare data as these wells are the deepest in Western Canada (>6000m) and contain a wide range of geological formations and rock compressive strengths. In addition, the Panther field utilized pad leases where each well on the pad is drilled with comparable well design of four different hole sizes per well.
Development of CBM in the Horseshoe Canyon (HSC) has exploded since its commerciality was first demonstrated in 2003. To date over 15,000 wells have been drilled and are producing from HSC coals. Quicksilver's development has been steady with approximately 1800 wells drilled and brought on-line between 2003 and 2009, and today operates 17 development pods located throughout the HSC fairway. This case study overviews Quicksilver's learnings and experiences from these activities including various aspects of geological and resource assessment, development tactics and recovery optimization, and presents practical datasets for appropriate management of the resource.
Geological investigation has been an important factor right from the outset of this play's development. Many initial concepts have been challenged and subsequent production data often shows discordant relationships with geological parameters used to calculate net pay, depth, and subsequently the OGIP. Water production trends, gas rate variability, anomalous seam contributions, non-linear pressure gradients, and variable permeabilities are discussed within this case study and the challenges that they present.
As development unfolds, production data has increasingly become a key factor in understanding these unconventional reservoirs, and is variable between areas and even within the development pods / areas themselves. Despite the variability, trends have been identified using production indicators and forecasts. A statistical approach is used to examine these trends, and in conjunction with the geology / resource characterization is enabling improved management decisions for optimal development. In particular variable density drilling, ranging from 2 wells per section to 8 wells per section, as well as various pilot higher density projects, is examined closely and provides valuable information from a reservoir development and optimization perspective. Impacts of sands completions as an add-on to
the primary CBM target are also investigated.
Seismic analysis was conducted to predict the orientation of the dominant fracture (cleat) system in a Cretaceous coal bed gas reservoir within the unconventional Coal Bed Methane (CBM) play in central Alberta, Canada. The extension of the method of analyzing the variation of seismic amplitude as a function of offset (AVO) to include analysis of amplitude variation as a function of azimuth (azimuthal AVO) was utilized. This technique was applied to characterize seismic azimuthal anisotropy, which indirectly predicts fracture system orientations.
The study focuses on identifying the azimuthal variation of the AVO response of the coal bed. By calculating three azimuthal AVO gradients from 2D multi-azimuth walkaway vertical seismic profiles (VSPs), the study revealed the existence of azimuthal anisotropy. A mathematical solution using these calculated AVO gradients defines the direction of the maximum change in amplitude with offset. This direction is always perpendicular to the orientation of the dominant fracture system.
The reliability of the approach used in this study demonstrates a promising method for characterizing fractures in unconventional gas reservoirs.
Shallow-gas fracturing is very prevalent in western Canada. Several thousand wells are typically drilled and completed in the shallow-gas fields every year. All these wells are typically hydraulically fractured. Before 1999, after testing for microtoxicity, the flowback fluid was allowed to be land farmed in southeastern Alberta. In that year, the Alberta Energy and Utilities Board began more stringent enforcement of Guide 58, which required that flowback fluid be disposed in a disposal well.
At that time, one operator typically had a project of 300 to 400 wells with an average of 5 fracs per day during spring/summer. When the fluid could no longer be land farmed, attempts were made to recycle the flowback fluid. The chemistry of the surfactant-gel fluid was insensitive to the water quality, which made the recycling concept successful. Several cost advantages were achieved, which will be detailed in the paper. These included freshwater costs, transportation costs, disposal costs, and chemical costs. An additional advantage that was realized involved a 50% reduction in the freshwater requirements for a project--a significant additional benefit because several years of drought conditions have caused water shortages in the area.
This paper will detail the chemistry of the fracturing gel, its field application, the optimized recycling operation, and the details on cost advantages achieved, as well as future direction for further reduction in freshwater usage on a project basis.
Shallow gas fracturing is very prevalent in Western Canada. Several thousand wells are typically drilled and completed in the shallow gas fields every year. All these wells are typically hydraulically fractured. Prior to 1999, after testing for micro-toxicity, the flowback fluid was allowed to be land farmed in Southeastern Alberta. In that year, the Alberta Energy and Utilities Board began more stringent enforcement of Guide 58, which required that flowback fluid be disposed in a disposal well. More recently, several years of drought conditions in the shallow gas areas of Southeastern Alberta have caused water shortages.
Prior to 1999, the flowback from a particular surfactant-based fracturing fluid could be successfully land farmed. One operator typically had a project of 300 to 400 wells with an average of 5 fracs per day during spring/summer. When the fluid could no longer be land farmed, attempts were made to recycle the flowback fluid. The chemistry of the surfactant gel fluid was insensitive to the water quality, which made the recycling concept successful. Several cost advantages were achieved, which will be detailed in the paper. These included fresh water costs, disposal costs and chemical costs. An additional advantage that was realized involved a 50% reduction in the fresh water requirements for a project.
The paper will detail the chemistry of the fracturing gel, its field application, the optimized recycling operation and the details on cost advantages achieved as well as future direction for further reduction in fresh water usage on a project basis.