Petrophysical analysis of downhole logs requires accurate knowledge of matrix properties, commonly referred to as matrix adjustments. In organic-rich shale, the presence of abundant kerogen (solid and insoluble sedimentary organic matter) has a disproportionate impact on matrix properties because kerogen is compositionally distinct from all inorganic minerals that comprise the remainder of the solid matrix. As a consequence, matrix properties can be highly sensitive to kerogen properties. Moreover, the response of many downhole logs to kerogen is similar to their response to fluids. Relevant kerogen properties must be accurately known to separate tool responses to kerogen (in the matrix volume) and fluids (in the pore volume), to arrive at accurate volumetric interpretations. Unfortunately, relevant petrophysical properties of kerogen are poorly known in general and nearly always unknown in the formation of interest.
A robust method of “thermal maturity-adjusted log interpretation” replaces these unknown or assumed kerogen properties with a consistent set of relevant properties specifically optimized for the organic shale of interest, derived from only a single estimate of thermal maturity of the kerogen. The method is founded on the study of more than 50 kerogens spanning eight major oil- and gas-producing sedimentary basins, 300 Ma of depositional age, and thermal maturity from immature to dry gas (vitrinite reflectance, Ro, ranges from 0.5 to 4%). The determined kerogen properties include measured chemical (C, H, N, S, O) composition and skeletal (grain) density, as well as computed nuclear properties of apparent log density, hydrogen index, thermal- and epithermal-neutron porosities, macroscopic thermal-neutron capture cross section, macroscopic fast-neutron elastic scattering cross section, and photoelectric factor. For kerogens relevant to the petroleum industry (i.e., type II kerogen with thermal maturity ranging from early oil to dry gas), it is demonstrated that petrophysical properties are controlled mainly by thermal maturity, with no observable differences between sedimentary basins. As a result, universal curves are established relating kerogen properties to thermal maturity of the kerogen, and the curves apply equally well in all studied shale plays. Sensitivity calculations and field examples demonstrate the importance of using a consistent set of accurate kerogen properties in downhole log analysis. Thermal maturity-adjusted log interpretation provides a robust estimate of these properties, enabling more accurate and confident interpretation of porosity, saturation, and hydrocarbon in place in organic-rich shales.
Lewis, Dennis Marathon Oil Co No Established Section-Rocky Mountain Region Rocky Mountain North America Lindahl, Carl Saudi Aramco Kingdom of Saudi Arabia Section Middle East and North Africa Li, Robert Shell Exploration & Production Co Gulf Coast Section Gulf Coast North America Liu, Chunlei Shell ...
Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
The Board of Directors is the policy-making and governing body of SPE. Its board committees oversee many of SPE's administrative and operating responsibilities. The board retains final authority on all SPE matters, including any actions the board committees may take. Sami Alnuaim has been with Saudi Aramco for 30 years, where he has worked in reservoir engineering, production engineering, research and development, and at the upstream computer center. He currently serves as manager of the petroleum engineering application services department where he leads information technology support for all upstream operations, including exploration, drilling, production, reservoir engineering, and facility design.
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Lee, Jonathan Ryder Scott Company, L.P. Gulf Coast Section Gulf Coast North America Lewis, Dennis Marathon Oil Co No Established Section-Rocky Mountain Region Rocky Mountain North America Lindahl, Carl Saudi Aramco Kingdom of Saudi Arabia Section Middle East and North Africa Li, Robert Shell Explora...
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.
The amount of trapped oil in hydrocarbon rich shale reservoirs recoverable through Enhanced Oil Recovery methods such as low salinity water flooding has been an ongoing investigation in the oil and gas industry. Reservoir shales typically have relatively lower amounts of swelling clays and in theory, can be exposed to a higher chemical potential difference between the native and injected fluid salinity before detrimental permeability reduction is experienced through the volumetric expansion of swelling clays. This fluid flux into the pore spaces of the rock matrix acting as a semi permeable membrane is significant enough to promote additional recovery from the extremely low permeability rock. The main goal of this paper is to determine how osmosis pressure build up within the matrix affects geomechanical behavior and hydrocarbon fluid flow. In this study we investigate Pierre shale samples with trace amount of organic content and high clay content as an initial step to fully understanding how the presence of organic content affects the membrane efficiency for EOR applications in shales using low salinity fluid injection. The same concept is also valid when slickwater is utilized as fracturing fluid as majority of the shale reservoirs contain very high salinity native reservoir fluid that will create large salinity contrast to the injected slickwater salinity.
The organic-rich reservoir shales typically have a TOC content of approximately 5 wt% or higher with TOC occupying part of the bulk matrix otherwise to be filled up by clays and other minerals. With less clay within the rock structure, the amount of associated clay swelling arising from rock fluid interaction will be limited. The overall drive of water into the matrix brings added stress to the pore fluid known as osmotic pressure acting on the matrix that also creates an imbalance in the stress state. The native formation fluid with salinity of 60,000 ppm NaCl has been used while 1,000 ppm NaCl brine is utilized to simulate the low salinity injection fluid under triaxial stress conditions in this phase of the study reported here. A strong correlation is obtained between the osmotic efficiency and effective stress exerted on the shale formation. The triaxial tests conducted in pursuit of simulating stress alteration under the osmotic pressure conditions and elevated pore pressure penetration tests indicated that the occurrence of swelling directly impact the formation permeability. These structural changes observed in our experimental results are comparable to field case studies.
Spectrograms computed from passive seismic trace data reveal the presence and types of signals that are emitted from fractures in reservoirs. The signals are dominated by resonances, are episodic, and are stimulated in different fractures at different times. Computing the spectrograms over hours and days allows clock times to be identified that can be used for imaging the active fractures in the reservoirs. Studies of passive seismic recorded during hydraulic fracturing suggest that these resonances are related to transmissive fractures and arise from fluid filled fractures. They are present in the trace data during quiet times, during stimulation times, and during reservoir production times and the resonating fractures are mapped for all of these conditions. These resonances appear in at least two forms. One type can be modeled as eigen-vibrations of isolated fractures excited by external forces and present in the data as dispersive resonance in the spectrograms. The second type appears as non-dispersive resonance interpreted as turbulent fluid flow moving in and out of connected fractures. By studying their characteristics, we have been able to identify dispersive and non-dispersive types of resonance in our data. The dispersive type can be excited in fractures that experience fracture dimension changes and also in fractures that are experiencing pressure changes within the fracture but do not have fluid flow. Using a unique data set from the hydraulic stimulation of an Engineered Geothermal System development, we have identified both types and have examples of the resonance starting as dispersive resonance, changing to non-dispersive resonance, and then terminating in microearthquake events.
Processing selected frequency and time windows of these emissions allows the resonance waveforms to be mapped back to their source locations using seismic depth migration. In quiet, pre-stimulation periods, resonances that show dispersion are more common. During stimulation, when fractures have been pressurized, non-dispersive resonance is more common perhaps caused by fluid flow in the fractures. In the transition between these states, previously closed fractures that are intersected by the stimulation will change their resonance character from dispersive type to non-dispersive type. Recordings during reservoir flooding or during production demonstrate a dominance of non-dispersive resonance. In all cases their locations can be mapped using multichannel recording and seismic depth migration methods.
Butler, Shane (University of North Dakota Energy & Environmental Research Center) | Azenkeng, Alexander (University of North Dakota Energy & Environmental Research Center) | Mibeck, Blaise (University of North Dakota Energy & Environmental Research Center) | Kurz, Bethany (University of North Dakota Energy & Environmental Research Center) | Eylands, Kurt (University of North Dakota Energy & Environmental Research Center)
Advanced characterization of the Bakken Formation, an unconventional oil and gas play of the Williston Basin, was performed via newly developed analytical tools of microscopic investigation in concert with standard laboratory methods. Characterization of an unconventional formation to understand the composition and distribution of framework grains, organic matter (OM), clay minerals, and porosity is difficult because of the extremely lithified nature of the lithofacies within the formation and the small grain and particle sizes. In this study, corroborative methods aimed to define micro- and nanoscale fabrics that impact parameters such as maturity, recovery, clay content, micropore networks, and CO2 interactions for either storage or enhanced oil recovery (EOR). Lateral and vertical variations in the rock fabric across multiple wellsites were observed on a micro- to nanometer scale with innovative analytical technologies.
Detailed morphologies and chemical compositions of ion-milled samples were obtained with field emission scanning electron microscopy (FESEM) coupled with energy-dispersive spectroscopy (EDS). Furthermore, a new software suite, Advanced Mineral Identification and Characterization System (AMICS), was used to classify and quantify mineralogy, OM, and porosity from the FESEM images. For validation purposes, x-ray diffraction was used to obtain bulk mineral and clay mineral data and x-ray fluorescence to obtain bulk chemical compositions of the samples. Advanced image analysis was performed on high-resolution FESEM images as another corroborative approach to characterize key features of interest within the lithofacies. Each sample consisted of high-resolution FESEM backscattered electron (BSE) images taken at multiple magnifications to maximize particle morphology in the fine-grained rock of the unconventional reservoir.
The data highlighted trends related to factors that impact CO2 transport and sorption in unconventional reservoirs. Segmented BSE images from the FESEM using program parameters that included texture, gray scale, and other morphological properties made it possible to estimate OM, clays, and porosity for each sample. The compositional analysis, including matrix porosity, OM porosity, and mineralogical composition maps, provided context for the potential of organic-rich and tight rock formations as CO2- based EOR targets or CO2 storage targets.
Advanced image analysis techniques were applied to better understand and quantify factors that could affect CO2 storage in the Bakken Formation, with an ultimate goal of improved method development to estimate CO2 storage potential of unconventional reservoirs. Discernible differences in fabric, mineral, and elemental content in comparable lithofacies across wellsites provided insight into the nature of the Bakken Formation, which could serve as a proxy for other tight rock, organic-rich reservoirs that could be potential targets for both CO2-based EOR and CO2 storage.