Learn more about training courses being offered. Learn more about training courses being offered. This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Learn more about training courses being offered. Current and future SPE Section and Student Chapter leaders are invited to engage and share. Every attendee leaves energised with a full list of ideas and a support network of fellow leaders. Those sections and student chapters actively participating in this workshop have consistently been recognized with awards as the best in SPE. SPE Cares is a global volunteering drive aimed at promoting, supporting and participating in community services at the SPE section and student chapter’s level. On its official launch this year at ATCE Dubai, SPE Cares will conduct a “Give a Ghaf” Tree Planting Programme to help preserve Ghaf’s cultural and ecological heritage. The Ghaf tree is an indigenous species, specific to UAE, Oman and Saudi Arabia. It is a drought tolerant, evergreen tree that can survive a harsh desert environment. The initiative not only aims to hold events/activities at ATCE, but also recognise community service that SPE members are already conducting in their respective student chapters and professional sections. The KEY Club, open daily, is an exclusive lounge for key SPE members. The lounge is open to those with 25 years or more of continuous membership, Century Club members, current and former SPE Board officers and directors, Honorary and Distinguished Members, as well as this year’s SPE International Award Winners and Distinguished Lecturers. DSATS (SPE’s Drilling Systems Automation Technical Section) will hold a half-day symposium featuring keynote presentations on urban automation. This symposium will explore technologies being used in developing smart cities through the automation of their infrastructure, transportation systems, energy distribution, water systems, street lighting, refuse collection, etc. These efforts rely on many of the same tools needed for drilling systems automation yielding increased efficiencies, lower maintenance and reduced emissions. Their knowledge and experience can guide the path being travelled by the oilfield drilling industry.
I cannot believe that a year has passed since I was inaugurated as SPE president in Dallas last September. My term has passed at the speed of light as I have traveled all over the world meeting our members and representing SPE at conferences and other events. Nine SPE sections have been awarded the SPE Presidential Award for Outstanding Section, the highest honor a section can receive. The awards will be presented to section officers at ATCE in Calgary, Alberta, Canada. SPE has two new offerings for the PRMS.
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems.
A useful first step in the characterization of any new coal area is to compare its characteristics with those of successful CBM projects. Table 2 summarizes the characteristics of several successful projects in the US and includes parameters related to reservoir properties, gas production, gas resources, and economics. The table shows that successful projects have many similarities, including high permeabilities and high gas resource concentration; however, the table does not include aspects such as government incentives or high-value markets, which could elevate a marginal project to commercial status.
Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for coalbed methane (CBM). A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. Organic matter constitutes more than 50% of coal by weight and more than 70% by volume. Type refers to the variety of organic constituents.
The objective of the project is to reconcile and quantify the impact of geological and completion variables that cause significant EUR differences in two recent wells drilled and completed in the Uteland Butte member of the Green River formation in Uinta Basin, Utah. While the geology and reservoir conditions are similar for both wells, the completion design and parameters are different (Ball-and-Sleeve vs. Plug-and-Perf, job size, treatment rates, well length, etc.).
The Asset Team uses a structured workflow consisting of several modeling tools: Rate-Transient-Analysis (RTA), Frac Modeling (FM) and Reservoir Simulation (RS) to address and quantify the impact of each variable: Job size, Treatment Rate, Frac count per Stage, Well Length and the effect of clays.
The workflow began with a performance evaluation of the high EUR well (Plug-and-Perf, large job) with RTA and Frac modeling; followed by history-match and prediction of the EUR with the RS model. In the subsequent workflow, a single variable is changed in each modeling step, while others are held constant -- as such, the EUR impact for each variable can be quantified. The result from each step is calibrated with the actual performance observed in the field.
This model-based approach successfully quantified the production impact of each variable. Subsequently, the key drivers can be determined which explains the estimated EUR difference between the two wells. This work drives us to conclude that due to varying pressure, PVT and lithology across the field, different completion designs shall be utilized. The team has gained valuable insight on how to implement different completion techniques with varying job size and design for the basin. Currently, these results are used to drive the well designs and approval; with the long-term objective of optimizing the Field Development Plan.
Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Marshall, Craig (University of Kansas) | Goldstein, Robert (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
Microscopic analysis including transmitted light, UV epifluorescence, BSE, and FIB-SEM carried out on Lower Eagle Ford (LEF) shale samples, selected from similar depths, show complex depositional fabrics, kerogen, migrated organic matter, and diagenetic history. It is well known that LEF samples contain depositional kerogen and migrated organic matter. Much of the migrated organic matter occupies diagenetically reduced primary porosity. Some of this organic matter is not porous, while some contains large pores and other contains a fine network of nanopores. Where thermal maturity is one control on porosity in organic matter, there is also a control of composition and origin. This paper investigates the chemistry of organic matter in-situ using Raman spectroscopy, to begin to understand what, other than thermal maturation, leads to porosity in both depositional kerogen and migrated organic matter. This is used to evaluate the nature of the pores in LEF, and to assess the impact of hydrocarbon gas injection on organic porosity.
Thin sections of the lower Eagle Ford shale samples are examined with transmitted light microscopy to select samples for Raman spectroscopy, after studying with FIB-SEM to analyze distribution of porosity in organic matter. In the Raman spectra, the separation between the D and G bands, the width of the G-band, and the intensity ratio of the D-to-G-bands are typically ascribed to maturity-related changes. However, composition and origin of the organic matter may also have an effect. The Raman spectra are analyzed to characterize the different types of porous and non-porous organic matter at the same depth. Then, samples are subjected to gas injection in the laboratory in preparation for a gas huff-n-puff operation, and changes in Raman spectra are analyzed once again.
BSE images show depositional kerogen is found as isolated bodies, lamellar forms, and fine material disseminated in the matrix. Transmitted light and UV microscopy reveal that some of this is non-fluorescent and some is fluorescent. Cement-reduced intraparticle pores, other primary pores, intercrystalline pores, and micro-fracture and micro-breccia pores contain migrated organic matter (OM), none of which fluorescences in UV. FIB-SEM images show the migrated OM has either spongy nanopores, larger bubble/meniscate pores, or no pores, all in the same sample. Raman spectroscopy analysis on the different types of organic matter show examples where both G- and D- bands are visible with distinctive separation, intensity ratio, or width, or where the D-band is absent. Moreover, the effect of gas injection on the different types of organic matter is inferred from the G- and D- bands.
This work improves our understanding of organic pore generation and modification, which influences pore size distribution and pore tortuosity, the underlying factors in gas huff-n-puff recovery in shales. It expands the utility of Raman micro-spectroscopy as a tool in understanding the evolution of pore systems and organic constituents in shale. It also presents an in-situ molecular structural study of the effect of hydrocarbon gas huff-n-puff on the different types of organic matter.
The results of an investigative research study on the impact of the in-situ stress, shale matrix composition, maturity, amount of organic matter and clay composition affecting the anisotropy level of the geomechanical properties have been discussed in this paper. These parameters are among the key factors known to control the geomechanical properties in organic-rich shale formations. Organic-rich shale formations with different mineralogical compositions and organic matter maturity have been measured under uniaxial and triaxial stress state along with the field data from limited number of the wells in these shale basins where the core samples are obtained to investigate the role of each factor on the level of geomechanical anisotropy.
The field data has been analyzed to compare the trends obtained from the laboratory data collected under customized controlled field conditions to the field data trends. Artificial Neural Network (ANN) analysis was used in wells without full log suits to obtain the anisotropic geomechanical parameters. The results highlight the maturation, organic richness and clay composition effect on the recorded field data as well as the geomechanical properties obtained from the laboratory measurements.
The stress and fluid sensitivity of shale formations have been well recognized since the early days of conventional reservoir drilling, completion and production operations as they typically require special attention for minimizing wellbore instability during drilling and maintaining high integrity wells throughout the life cycle of these wells. Shales are highly heterogeneous and anisotropic formations and their source rock characteristics also have introduced further complexities with the organic matter and compositional variations throughout the areal extent of the reservoirs. These variations and their alterations as a function of the level of maturity of the organic matter require further study for better understanding of the differences and similarities between the seal shales and reservoir shales and the role of the organic matter and its maturity level in these differences. One of the critical aspects of the organic matter presence is in quantification of shale mechanical properties and strength and their direction dependence for successful field development. The level of maturity of the organic matter also influences the mechanical, acoustic, petrophysical and failure properties of organic rich shale formations. The mineralogical composition typically deviates from carbonate rich to quartz rich in the rock matrix with clay and organic matter amount and distribution heterogeneity in the reservoir. The layered structure introduced by the depositional history of the formation along with the heterogeneity in the distribution of organic matter result in various degree of anisotropy in reservoir properties (Sondergeld and Rai, 2011; Vernik and Milovac, 2011). A better understanding on the anisotropic characteristics of the shale formations and key parameters impacting the anisotropy is essential for field operational success from exploration studies for seismic attributes to reservoir characterization, drilling and hydraulic fracture design and production optimization.
Below is a list of basins and fields; however this is a short list since there are more than 65,000 oil and gas basins and fields of all sizes in the world. However, 94% of known oil fields is concentrated in fewer than 1500 giant and major fields. Most of the world's largest oilfields are located in the Middle East, but there are also supergiant ( 10 billion bbls) oilfields in India, Brazil, Mexico, Venezuela, Kazakhstan, and Russia. Add any basins or fields that are missing from this list!
Petroteq Energy announced that it has acquired additional acreage in the resource-rich Uintah basin. The company has finalized the acquisition at auction of a 100% interest in two leases for 1,312 acres of land within the Asphalt Ridge, Utah, area. A report commissioned by Petroteq from Chapman Petroleum Engineering dated 30 April states that the newly acquired leases contain 7.331 million bbl of contingent resource, expanding Petroteq's total contingent resources by 8.5% to 93.4 million bbl. Chapman estimated that 93.4 million bbl would, under favorable circumstances, support very positive economics. These 93.4 million bbl would be classified as a Contingent Resource under Canada's current NI 51-101 standards of disclosure for oil and gas activities and Canadian Oil and Gas Evaluation Handbook guidelines.