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Gas to Wire (GTW) is a concept which will aid the UK to meet their growing energy demand as, GTW will allow marginal and somewhat depleted gas fields to convert natural gas to electricity onsite, with the electricity exported via subsea power cables - the concept is not yet fully commercialised offshore. This paper initially discusses what is GTW and then investigates two separate cases: the first focuses on evaluating the viability of GTW for the Kumatage gas field which is 78 km close to shore (located in the Southern North Sea) (
A discussion is also included in GTW's potential to work in conjunction with renewable technologies, such as tying back to Hornsea Project Four which is an offshore windfarm currently under the preapplication stage by Ørsted (hornseaprojects, 2019). It will be approximately 65 km from the Yorkshire coast and will be close to the Theddlethorpe and Bacton gas terminals (National Grid, 2019). By doing so, the electricity produced from Kumatage would need to be exported via a power cable to the windfarm. This study also discusses GTWs compatibility with existing renewable technologies to reduce carbon dioxide (CO2) emissions. By combining the findings of this paper, a further review of the potential of GTWs ability to unlock more marginal and stranded assets and contributing to the security of future UK energy supply. What can also be explored further from this paper is multiphase flow in the reservoir to then be able to model GTW to other offshore gas fields in the SNS.
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.
Chen, Zeliang (Rice University) | Wang, Xinglin (Rice University) | Jian, Guoqing (Rice University) | Zhang, Leilei (Rice University) | Dong, Pengfei (Rice University) | Singer, Philip (Rice University) | Hirasaki, George (Rice University)
Abstract Unconventional resources are of great importance in the global energy supply. However, the ultralow permeability, which is an indicator of the producibility, makes the unconventional production challenging. Therefore, the permeability is one of the critical petrophysical properties for formation evaluation, along with the rock porosity and compressibility. There are many existing approaches to determine permeability in the laboratory using core analysis. The methods can be divided into two categories: steady-state and unsteady-state approaches. The steady-state approach is a direct measurement using Darcy's law. This approach suffers from the accuracy in the measurement of low flow-rate and the long run-time. The unsteady-state approach includes pulse decay, oscillating pressure, and GRI methods. These approaches are complicated in terms of set-ups and interpretations. Both steady-state and unsteady-state approaches typically have a constraint on the maximum differential pressure. We propose a novel unsteady-state method to determine the permeability by transient-pressure history matching. On the experimental side, the ultralow-permeability core undergoes 1-D CO2-flooding experiments, during which the transient pressure is monitored for history matching. Another two rock properties that determine the transient-pressure history, namely the rock porosity and the pore-volume compressibility, are calculated based on the mass balance of CO2 at different states. On the simulation side, the transient-pressure history is simulated using real-gas pseudo pressure and table lookup to deal with the non-linearity in fluid properties. The free parameter, permeability, in the simulation is adjusted for history matching to determine the rock permeability. Our simulation can generate high-quality transient-pressure history with the capability of handling the non-linearity and singularity in fluid properties. Our new unsteady-state method is validated by the standard steady-state method. The advantages of this unsteady-state approach are: 1) it can be implemented with simple set-ups; 2) it can be finished within a considerably short-time period; 3) the data interpretation is straightforward; 4) it can be implemented over broad pressure ranges, even with phase transitions of the permeating fluids, not limited to CO2. This approach is a valuable addition to existing permeability measurement methods.
Liang, Guangyue (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Shangqi (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Yang (Research Institute of Petroleum Exploration and Development, CNPC) | Zhou, Jiuning (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Zhangcong (Research Institute of Petroleum Exploration and Development, CNPC) | Han, Bin (Research Institute of Petroleum Exploration and Development, CNPC) | Bao, Yu (Research Institute of Petroleum Exploration and Development, CNPC)
Steam assisted gravity drainage (SAGD) has been intensively applied in heavy oil or oil sands Projects. However, it is commonly limited by even thin shale laminae, which can greatly reduce inter-well connectivity and conformance along horizontal sections, leading to lowering production rate. Thus, new dilation stimulation technologies by polymer solution or steam injection at different stages were proposed to improve oil sands SAGD performance.
Based on the data of mini-fracture test, tri-axial test and core test of polymer displacement, technical feasibility of dilation technology by polymer solution injection in start-up process was evaluated by coupled geomechanical and thermal simulations, considering the mechanisms of polymer adsorption, degradation reaction, shear thinning and residual resistance, etc. Similarly, technical feasibility of steam dilation in normal SAGD process was discussed. On the basis, they were separately tested in two typical well pairs. The follow-up temperature fall-off analysis and history matching of field trials over 1 year were conducted to demonstrate the improvement of porosity & permeability and steam conformance. Specially, the key to success of dilation was also analyzed.
The feasibility study indicates that these dilation technologies can create vertical dilated zone, accelerate start-up process and obtain greater conformance under fine control of low injection rate, low volume and high pressure. The main principle lies in that they combine shear dilation and micro tensile parting to further loosen unconsolidated sand particles and create micro-cracks. While the reservoir is first dilated to form a high-porosity and high-permeability conduit connecting the SAGD well pair, the polymer solution that can mitigate water leak-off is then injected into these newly created pore spaces, yielding relatively uniform dilated zone with a large storage volume. Compared with adjacent well pairs, the temperature fall-off and history matching results demonstrate the great improvement of inter-well porosity & permeability (especially water permeability), vertical connectivity and steam conformance. Both steam consumption and circulation time reduced nearly by half. Besides, early production rate improves in follow-up SAGD process.
The dilation technologies by polymer solution or steam injection were first successfully applied in Canadian oil sands project, and they were first presented by combining several laboratory tests, field trials and history matching. The field experience and findings can help to improve the SAGD performance and economy of super heavy oil and oil sands projects, especially for heterogeneous reservoir with shale laminae.
The paper presents the results of a multiparametric analysis of the helium saturation zone after its injection into a porous gas reservoir, the dynamics of its content in a withdrawn gas mixture and the helium recovery factor (target parameters). The calculations are performed on a three-dimensional composite hydrodynamic sector model of a homogeneous anisotropic reservoir of a virtual gas deposit. Based on the results obtained, the geological and technological factors are ranked according to the absolute value of the change of target parameters when the input parameters change. The dynamics of the influence of geological and technological factors on the target parameters is described concerning different withdrawn gas volume from the initial reserves. The identified relationships can be useful for planning of the experimental helium injection and the placement of exploitation wells at underground helium storage.
Ghaderi, S. M. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Ghanizadeh, A.. (University of Calgary) | Barry, K.. (Crescent Point Energy Corp.) | Fiorentino, R.. (Crescent Point Energy Corp.)
Abstract Conventional oil production has occurred from the Bakken Formation in Saskatchewan since the mid-1950s. However, with successful implementation of multi-fractured horizontal well (MFHW) technology, the low-permeability (unconventional) Bakken has experienced ever increasing E&P activity on both sides of the US/Canada border. Prior to 2005, the Bakken in Saskatchewan had less than 100 active producers in the region but has increased to more than 2,500 producing wells since then (Sekar, 2015). Although improvement in hydraulic fracture properties and infill drilling remain the focus of recovery enhancement from the Bakken, low oil recoveries and steep initial oil decline rates are experienced using primary recovery operations, even after application of MFHW technology. Therefore, many pilots have been executed to determine the viability of waterflooding for maintaining oil rates and improving recoveries through reservoir pressure maintenance and sweep efficiency enhancement. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. MFHWs were used as both injectors and producers for this pilot. Five years of production/injection volumes for these wells, along with pressure data, were matched using a black-oil simulator. The calibrated model was then used to predict the long-term performance of the pilot. Finally, this model was used for further investigation of parameters affecting the performance of the waterflood operation along with assessment of EOR (gas injection) schemes applicable to the Bakken Formation. Two important conclusions can be derived from this study: 1) waterflooding can be effective in tight oil reservoirs using MFHWs as injectors and producers and, 2) careful characterization of vertical changes in reservoir quality using laboratory-based measurements are important for improving the quality of the history match and resulting forecast scenarios. For 2), permeability heterogeneity was quantified using profile permeability measurements corrected to ‘in-situ’ stress conditions.
Summary Low recovery factors in ultratight unconventional reservoirs such as the Bakken provide both a challenge and an opportunity for depletion optimization. However, meaningful improvements can only be realized with a fundamental understanding of reservoir heterogeneity and rock properties such as porosity, saturation, permeability, and wettability. Although the laboratory methods used to measure these properties are considered mature for conventional reservoirs, the multiscale complexity and heterogeneity of unconventional reservoirs pushes the limits of conventional methods, necessitating development and application of advanced laboratory and petrophysical methods. This paper presents an integrated characterization of the Middle Bakken reservoir. A variety of approaches were used to measure permeability from core plug samples, including air permeability, Klinkenberg permeability, steady-state and unsteady-state liquid permeability, and MICP derived permeability. The results of these studies show that an integrated approach, using a combination of measurement methods, can enable quantification of matrix permeability with reasonable certainty, Wettability and fluid distribution are also key unconventional reservoir parameters. An approach coupling a porosity/saturation mapping technique with mineralogy mapping at the pore scale has the potential to shed light on the intrinsic wetting behavior of the reservoir as a function of mineralogy. The last portion of this characterization study examines rock typing using high-resolution imaging techniques. Three key rock types identified in the Middle Bakken provide a framework for mapping reservoir heterogeneity and a basis for generating upscaled models which can enable future optimization of the field development.
Abstract A close coupling of geoscience and engineering disciplines has generated a history-matched model for the Dukhan Arab C reservoir serving as a platform for testing of forward development strategies. The Arab C reservoir is a heterogeneous organization of limestone and dolomite lithologies deposited on a shallow water Jurassic ramp system. Hydraulically, the 80ft thick interval represents a network of grainstone conductors compartmentalized by muddy carbonate baffles resulting in layer-constrained dynamic behavior. The reservoir has been under development for over sixty years, with an early period of natural depletion followed by peripheral water injection utilizing hundreds of vertical and horizontal producers and injectors. As part of an effort to update the field development plan, a new geologic model was developed that formed the basis for reservoir simulation studies and depletion planning. Initially, a series of tests were conducted to determine the sensitivity of model responses to input variables, and these tests helped to guide subsequent static model adjustments. Horizontal permeability defines aquifer response, waterflood front advance and early pressure trend, while vertical permeability significantly controls subsequent dynamic behavior. Thin mudstone baffles are common at parasequence boundaries and their continuity and association with stylolites determines inter-zonal vertical communication. Variable salinity of injected water was shown to have a large impact on water encroachment patterns and derivation of appropriate relative permeability functions improved the calibration of the full-field dynamic reservoir simulation model. Knowledge of the controlling parameters ranked according to dynamic sensitivity facilitated an emphasis on regional variations constrained by geological trends and helped to minimize the requirement for localized adjustments. Lessons learned as a result of this geoscience-engineering feedback can expedite future model building by focusing technical expertise on the most critical parameters controlling fluid flow. Introduction The Qatar Petroleum-operated Dukhan Field is located onshore Qatar, approximately 80km west of Doha (Figure1). The Arab C reservoir interval is a carbonate anticlinal structure lying 5500–7000ft below the surface and is approximately 70km long by 8km wide. The Arab C interval is about 80ft thick with moderate to high reservoir quality (typically 18% porosity, 100mD permeability). A high degree of vertical heterogeneity relates to a sedimentary origin in a near-shore shallow ramp environment featuring high-order depositional cyclicity. Lateral ranges of 1–4km for baffling thin-beds supports a localized layer-constrained dynamic behavior, though communication pathways are impacted by sporadic occurrences of cross-cutting conductive and resistive faults. Arab C production development began in 1949 with a period of natural depletion followed by conversion to water drive in the 1960s via peripheral water injection utilizing hundreds of vertical and horizontal producers and injectors.
Abstract Estimating basic properties of unconventional shale reservoirs—such as permeability and porosity—is critical for reservoir evaluation, formation damage prediction, hydraulic fracture design, and performance forecasting. Several techniques can be used to measure these properties. For instance, the Gas Research Institute (Luffel et al. 1993) uses crushed rock, modeling high-resolution images of micron-sized samples, pulse decay, steady-state techniques to evaluate the permeability, and gas expansion and mercury immersion for porosity of a shale sample. However, the accuracy and reliability of these techniques are not well-established for unconventional reservoir rocks because of concerns about the flow regime, the absence of net confining stress, the sample size, and the imaging technique resolution. This paper presents the results of a round robin permeability and porosity measurement performed at several commercial and research laboratories. The permeabilities of the evaluated samples vary from 10 nanodarcy to 10 microdarcy, and their porosities vary from 5 to 10%. A wide range of natural and synthetic material was computed tomography (CT) scanned and microscopically examined. Selected samples were used based on their suitability for the desired range of porosity and permeability. The samples were examined before and after drying in a vacuum oven and then tested under several stress cycles. Gas permeability was measured by use of steady-state, transient pulse decay techniques and derived from mercury injection data. Porosity was measured by use of the gas expansion technique and mercury immersion. Image analysis of focused ion beam-scanning electron microscope (FIB-SEM) was also used to model permeability. Klinkenberg permeability was derived from apparent permeability by use of a range of mean pressures to examine validity of the Darcy flow regime. The results of the round robin testing of porosity and permeability indicate: Darcy flow is the predominant flow regime in shales with permeability as low as 10 nano-darcy, based on Klinkenberg characteristics and flow rate-pressure drop criteria. Permeability measurement on 10 nano-darcy to 10 micro-darcy permeability core plugs, under 400 to 5000 psi, is feasible and repeatable with a reasonable uncertainty range, at qualified commercial laboratories. Porosity data showed uncertainties in the range of ±1.0 p.u. for the natural samples. Steady-state method provides similar results from different laboratories, as long as an identical procedure is implemented. Uncertainty in steady-state permeability data from different laboratories could be as high as ±150%. Liquid permeability testing by use of supercritical fluid or laboratory fluid (Decalin) provides a complementary and valuable piece of datum. Rotary sidewall core plugs may provide higher quality core standards for shale material testing because the core plugging takes place under reservoir temperature and stress conditions.
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.