|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Cuttings are an undervalued resource that contain vast amounts of relevant formation evaluation (FE) data in the form of entrained volatile chemistries from present day formation liquids/gases. Analysis of these chemistries in cuttings, or other materials (core, side wall core, and muds), enables decisions from well level completions to acreage/basin assessments on an operational timescale. This work compares analysis of rock volatiles to traditional FE (water saturation and permeability) data to demonstrate correlations to field studies in the Delaware Basin and the STACK. The field study from the SCOOP demonstrates how the analysis can be used to drive completion decisions; studies from the STACK demonstrate how the analysis drove acreage assessment and utilization decisions. All cases are presented from nonhermetically sealed samples showing the applicability of the analysis to fresh or legacy materials.
A unique cryo trap-mass spectrometry (CT-MS) system has been developed by Dr. Michael Smith enabling the gentle extraction of volatiles from cuttings, or other materials, and the subsequent identification and quantification of the extracted chemicals. All possible chemistries (hydrocarbons, organic acids, inorganic acids, noble gases, water, etc.) are extracted by gentle volatilization at room temperature under vacuum conditions and concentrated on a CT; the chemistries are separated by warming the CT and volatilizing as a function of sublimation point and then analyzed by MS. Advantages of this CT-MS over GC-MS are that chemicals that would not survive the conditions of a heated GC system can be analyzed and that the analysis does not require different columns as a function of the species type analyzed. The analysis works on both water and oil based mud systems. These results are combined with a geological interpretation to enable application.
The comparison field studies show that the analysis successfully reproduced Sw and permeability trends from petrophysics and sidewall core analysis. The SCOOP field study identifies the mechanism of underproduction in a Hoxbar well and a simple completion strategy for the lateral that would have significantly reduced costs while enabling equivalent production. The STACK field study was utilized by an operator to evaluate and understand the petroleum system across their acreage and enabled unique acreage utilization decisions in terms of well placement and lateral trajectory.
O’Toole, Timothy (Chevron North American Exploration and Production Company) | Adebare, Adedeji (Chevron North American Exploration and Production Company) | Wright, Sarah (Chevron North American Exploration and Production Company)
The Second Bone Spring Sand is currently the second most drilled bench within the Delaware Basin. Some of the main struggles encountered by operators is determining the combined optimal well spacing, targeting, and completions design for a given bench. Moreover, to economically and efficiently develop any bench within the Permian, a strong understanding of reservoir heterogeneity is needed. Recent work has provided insight into the controls on Second Bone Spring Sand (SBSS) production and optimal development strategies. A key driver of well performance is reservoir architecture, and one must understand the spatial variability of their field area as it affects the overall development strategy that is ultimately deployed (i.e. completions design, well spacing, targeting, etc.). Furthermore, a deeper look into completions trends within the SBSS has closed the gap in optimizing dollars spent in relation to production gains.
The Permian Basin of southeast New Mexico and west Texas has been a highlight of North American oil and gas exploration, development, and production for decades. This basin is further sub-divided into the Midland and Delaware Basins (Figure 1), which are separated by the Central Basin Platform. The Delaware Basin is bounded to the east by the Central Basin Platform, to the west by the Diablo Platform, to the north by the northwest shelf and to the south by Marathon-Ouachita orogenic belt.
Formation of the Delaware Basin began with the Tobosa Basin (Galley, 1958) that existed from the Late Pre-Cambrian through the Mississippian, with compression and faulting during the Ouachita-Marathon Orogeny causing the Central Basin Platform to rise (Schumaker, 1992; Soreghan & Soreghan, 2013).
Climate during deposition in the Delaware Basin was generally arid, with the basin resting at approximately 5-10° north of the equator (Soreghan & Soreghan, 2013; Ziegler et al., 1997). Sediment is thought to have been sourced via aeolian transport as well as via fluvial systems (Fischer & Sarnthein, 1988; Soreghan & Soreghan, 2013).
Deposition in the Delaware Basin fluctuated between carbonate-rich highstand and silica-dominated lowstand conditions with high TOC mudstones forming farthest from the shoreline. This reciprocal sedimentation depositional history has led to mixed-lithology rock with highly variable facies, such as the Wolfcamp and Bone Spring Formations that are major targets of unconventional development today. The Leonardian Bone Spring Formation especially displays this lithologic alternation and is comprised primarily of three major siliciclastic members divided by carbonates that are named in order of increasing depth (Figure 2), in addition to regional members such as the Avalon and Harkey Mills Sandstone. This paper focuses on the middle siliciclastic member, the Second Bone Spring Sand (SBSS), which was deposited as a lowstand submarine fan system.
Mohsin, Labib (Oman Oil Company Exploration and Production LLC) | Alshukaili, Alwaleed (Oman Oil Company Exploration and Production LLC) | Mahesh, Arathi L. (Schlumberger) | Lewis, Richard E. (Schlumberger) | Strapoc, Dariusz (Schlumberger) | Bondabou, Karim (Schlumberger) | Pisharat, Maneesh (Schlumberger) | Al Ghafri, Ali Maayouf Dhafyiar (Schlumberger) | Fornasier, Ivan (Schlumberger) | Peralta, Juan (Schlumberger)
Production results from the Natih B oil-bearing clean (<10% clay) Cretaceous carbonate rich source rock are correlated to an integrated interpretation of measurements and postproduction geochemical analysis on oil sample. The full picture from pilot well location selection, based on an unconventional resource assessment, to sidetrack horizontal well design and optimization to the findings from the post-multistage fracturing production test is presented and discussed. A full logging suite including while-drilling surface measurements (diffuse reflectance infrared Fourier transform spectroscopy - DRIFTS, and the advanced mud gas logs – AMGL) was acquired in the pilot vertical well. Reservoir Quality (RQ) and Completion Quality (CQ) assessments were made by integrating all available measurements, and the while-drilling cuttings data served as calibration for log-derived TOC and minerology, comparison with in-situ fluid type and maturity (recent while-drilling measurements on source rocks). The RQ assessment indicated the reservoir to be a low-porosity (3 to 7 p.u.) laminated carbonate with a high resistivity (>10,000 ohm.m), kerogen-hosted-porosity layer that alternates with a kerogen-lean layer with conventional pores. While-drilling two independent proxies were applied to assess the thermal maturity. Kerogen maturity from DRIFTS was 0.6 to 0.7% vitrinite reflectance equivalence (VRE), and maturity computation from mud gas ratios using AMGL indicated ~0.5-0.8% VRE, both implying early-to-peak oil maturity level. The pilot well could not be tested due to operational issues and the best landing-point selection for the lateral was based on integrated RQ-CQ analysis in the pilot well. The lateral was geo-steered using logging-while-drilling measurements (distance to boundary tool and high resolution image logs), DRIFTS TOC, and AMGL logs. After drilling the lateral, a wireline triple combo with dipole sonic was acquired. A RQ-CQ evaluation was performed for completions and hydraulic fracture design optimization. The hydraulic fracturing operation was successful with three stages propped as per engineered design. The most significant new finding is the good correlation between the recent advanced while-drilling (available in real-time) proxies for kerogen and fluid maturity with the fluid maturity level from the geochemical fingerprinting (SARA and biomarker analysis) of the produced oil sample and the good agreement of the same with the production performance of the Natih B in the lateral. The workflows and lessons learnt during the full cycle of the Natih B exploration in Oman can be applied in parallel scenarios (exploration of source rocks in general or exploration of the Natih B source rock or equivalents elsewhere in the region).
Zhai, Hao (The University of New South Wales) | Canbulat, Ismet (The University of New South Wales) | Hebblewhite, Bruce (The University of New South Wales) | Zhang, Chengguo (The University of New South Wales)
Weak rock mass strength estimation is a long-lasting challenge associated with geotechnical engineering due to its complex nature and limited definition. Weak rock masses normally refer to low strength, highly fractured decomposed and tectonically disturbed rocks which have properties intermediate from brittle rocks to ductile soils. Since the behavior of weak rock mass has not been fully understood, it is a common practice to apply existing empirical approaches, which are developed for competent rock masses influenced by joints, to determine their mechanical properties. This paper reviewed the current empirical approaches, and detailed weak rock mass strength calculations based on rock matrix, joint layout, joint condition and external factors. The limitations associated with these methods are discussed, and suggestions are provided for the selection of suitable methods.
Determination of weak rock mass properties is a significant challenge in geotechnical engineering. In general, weak rocks are considered to be the transitional material between competent rocks and soil, therefore, their behavior converges to competent rock at its upper bound and soil at the lower bound. Despite significant amount of research, methods to estimate in-situ behavior and strength of weak rock masses remain to be relatively fragmented and incomplete. The difficulty of determining their behaviour is mostly caused by the complex nature and inadequate definitions. Different origin and alteration process of weak rocks result in variant properties that inevitably influence their overall behaviour. Hence, it is important to understand the differences in their property that inherited from both previous phase and alteration process and to adopt suitable approaches to estimate their strength according to these features.
In practice, the term weak rock commonly refers to both young sedimentary rocks with low compressive strength and heavily altered hard rock with intense structures [1-3]. Based on the origin and geological alterations, weak rock can be classified as young sedimentary rock, weathered competent rock and tectonically disturbed competent rock as shown in Fig. 1. Young sedimentary rocks such as mudstone and claystone contain poor lithification and weak particle cementation. The strength of them can be described by the ISRM definition of weak rocks with uniaxial compressive strength (UCS) being 0.5 MPa to 25 MPa [2, 3]. Weathered competent rocks such as sandstone can also be considered as weak rock. During prolonged exposure, some rock mass components start to break down and crack along pre-existing micro fractures. As a result of weathering, the well-developed, interconnected defect fabric deteriorates the integrity of the rock mass, thus lead to a reduction of the overall mechanical strength. This type of rock is well represented in Rock Mass Rating (RMR) and Geological Strength Index (GSI) classification systems as poor quality rocks with ratings lower than 25 and 20 respectively or less than 0.1 in Q system. In practice, there is a tendency to consider tectonically disturbed competent rocks, which preserves limited original structures formed in lithification, as weak rock mass . Due to destruction of original structure during folding and shearing, it’s common to observe widely existing intensive fractures. Thus, this type of rock has very low mechanical properties similar to other types of weak rock masses. Marinos and Heok’s study of flysch in 1998 provides a good example of such weak rock [4-6].
Waveform-based inversions have been receiving a considerable attention over the recent years in the oil and gas industry. Going beyond the assumptions behind the amplitude-variation-with-offset/angle inversion and honoring complex effects of wave propagation, such waveform-based methods are effective in accurately delineating the subsurface reservoir properties. In this work, we develop a prestack waveform inversion method using multilevel parallelization and apply it on a real data volume from the Rock-Springs uplift, Wyoming, USA. We further use the inversion results to identify some key formations. Additionally, because the primary purpose of acquiring the Rock-Springs uplift seismic data was to characterize the subsurface for carbon dioxide sequestration, we also use our inversion results to analyze some potential target reservoirs and their associated seals. By demonstrating that our analysis is capable of producing a high-resolution image of the subsurface elastic earth properties, we conclude that prestack waveform inversion is an effective tool for reservoir characterization.
Presentation Date: Tuesday, October 18, 2016
Start Time: 10:45:00 AM
Presentation Type: ORAL
Draugen is a low structural relief oil field with a sandstone reservoir and, at production start-up, a 50m vertical oil column above the free water level. Reservoir quality is excellent with an average porosity of 29% and multi-Darcy permeability.
Draugen started producing light oil in 1993 and had a planned development life of 20 years. After reviewing options for improving recovery, several opportunities are being matured to extend production, aiming to raise the field recovery factor towards 70%. As part of this project, infill drilling to target un-swept attic oil plays an important role.
The infill 2013/14 campaign comprised four wells, drilled and completed in 2013/14 as per plan. The first well was drilled and completed in 2013; the second, third and fourth wells followed in 2014 with demonstrably better well placement results. A fifth well was later added to the sequence, as an accelerated project and based on the previous successful drilling campaign's learning. The well was drilled and completed in 2015, with similar excellent results.
The infill campaign utilized modern deep reading electromagnetic tools in the bottom hole assembly (BHA) in order to achieve the desired well placement. The tools were a key enabler, giving confidence that remaining (thickest un-drained) hydrocarbon resources identified from 4D seismic could be developed: target remaining attic oil columns were thin, that well placement was critical to effectively deliver the well objectives.
Schlumberger ultra deep reading resistivity tools were deployed in the first well during field testing phase, and as the campaign progressed, the Asset team worked closely with Schlumberger to develop well placement and project delivery. During the drilling campaign, the technology was commercialized by Schlumberger.
This paper will discuss the wells landing and geosteering strategy, the results and learnings, as well as the technology evolution throughout the drilling campaign.
Mirchi, Vahideh (Department of Chemical and Petroleum Engineering, University of Wyoming) | Saraji, Soheil (Department of Chemical and Petroleum Engineering, University of Wyoming) | Goual, Lamia (Department of Chemical and Petroleum Engineering, University of Wyoming) | Piri, Mohammad (Department of Chemical and Petroleum Engineering, University of Wyoming)
The recovery factor of waterflood operations is constrained by formation geology and pore trapping mechanisms. This is particularly important for unconventional reservoirs such as shale oil with ultra-low permeability and porosity. Surfactant flooding can be used in these reservoirs to reduce oil trapping and increase sweep efficiency due to a reduction in interfacial tension and wettability alteration. On the other hand, a major concern with surfactant flooding is the adsorption of surface-active agents on the reservoir rock leading to loss of chemicals. In this study, the behavior of a non-ionic surfactant was investigated in order to enhance oil recovery from a producing shale oil reservoir using reservoir crude oil and rock samples. In the preliminary experiments, phase behavior tests were performed in the presence of reservoir shale rock to monitor micro-emulsion stability. The critical micelle concentration (CMC) of this surfactant was determined by both surface tension measurements and spectroscopy. Dynamic interfacial tensions (IFT) and contact angles (CA) of the non-ionic surfactant in brine/oil/shale systems were then measured by the rising/captive bubble technique using a state-of-the-art IFT/CA apparatus at reservoir conditions (6840 psi and 116?) for different surfactant concentrations (0.005 to 0.5 wt%). The amount of surfactant adsorption from surfactant-brine solutions onto crushed shale rocks were measured using UV-Vis spectroscopy at different surfactant concentrations. The data could be fit to a Langmuir type adsorption isotherm. The adsorption parameters were determined and results were compared and discussed. This work shows that the non-ionic surfactant is able to reduce the reservoir oil-brine IFT from its original value (27 mN/m) down to 15 mN/m while exhibiting minimal adsorption on the shale surface.
Copyright 2013, held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors This paper was prepared for presentation at the SPWLA 54th Annual Logging Symposium held in New Orleans, Louisiana, June 22-26,2013 ABSTRACT Conventional and Unconventional Gas Resources (CGR, UGR) are a focus area for upstream studies in Saudi Aramco and its Permian clastic reservoirs in particular constitute a world class gas resource. Deposited originally in an Aeolian environment, tight rock partial-seals surround a distribution of permeable "sweet spots". Reservoir development is determined by a complex diagenetic process. The highlighted field is a typical example. During initial appraisal, a continuous gas column was interpreted from pre-production pressure data with a clear free water level. Yet, as development progressed, development wells encountered water up structure and pressure depletion showed a complex pseudo-compartmentalization, in contradiction of the initial model assumptions. As part of ongoing reservoir management, an extensive special core analysis program has been conducted on a comprehensive set of some 300 samples encompassing the range in rock quality present in the formation which ranged from highly permeable quartz rich dunes to diagenetically altered paleosols, siltstones and shales.The bulk of samples showed meso-and macro-pore structures typical of silt to clean sandstone dominated rock sequences. This is interesting because although these rock types should be filled with gas, given the expected column height of approximately 1000 ft, none of the rocks examined showed a gas sealing potential of more than a few hundred feet.