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Results
Abstract Results of laboratory research conducted in the framework of laboratory program developed jointly by a technology provider and an offshore oil-gas fields operator are presented in this paper. The laboratory program included optimal list of experiments for testing physical and technological properties of the physico-chemical water shut-off agent, resulting in a ready-for-pilot solution at minimum cost and time. The studied water shut-off agent is an emulsion system with nanoparticles (ESN), which is an inverse emulsion augmented by the synergy of natural and artificial surfactants with supercharged silicon dioxide nanoparticles. The ESN consists of three liquid components: sea water, diesel and nanoparticle-based surfactant. One of the main tasks of this research was to study such features of the ESN as selectivity of blocking impact to water-bearing zones and reversibility of blocking effect in the oil-bearing zones of sandstone reservoirs in the Lower Miocene (2950 psi and 91°C) and Late Oligocene (3900 psi and 107°C) hydrocarbon formations. As a basic requirement from the operator, the ESN had to be stable at the said reservoir conditions and compatible with reservoir and process fluids. Besides that, the operator wanted to confirm that the ESN is an easy-to-handle water shut-off agent in the offshore environment, meaning that it can be prepared with ordinary equipment available at the vessel, all components are liquids easily mixed to each other at ambient conditions and ready-to-use composition properties do not change in time within the operation offshore. Thus, the laboratory program was executed in three successive stages, divided based on the experiment conditions: ambient; pressure & temperature; modeled reservoir conditions. In result, the ESN performed as stable and compatible water shut-off agent and met all requirements of the operator. In the series of core floods, conducted on eight sandstone cores of different permeability and saturation, it was confirmed that the ESN selectively and fully blocks water-saturated cores, while the oil-saturated cores permeability decreased slightly with clear tendency to full recovery under the flow of hydrocarbons.
- South America > Brazil (0.68)
- Asia > Vietnam > South China Sea (0.46)
- North America > United States > Oklahoma (0.28)
- (3 more...)
- Phanerozoic > Cenozoic > Paleogene > Oligocene (0.72)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.60)
- North America > United States > California > Los Angeles Basin > Wilmington Field (0.99)
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 9-2 (0.99)
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 15-2 > Rang Dong Field (0.99)
- (4 more...)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Electrical Treatment to Revive Dead Gas Wells due to Water Blockage
Aljuhani, G. (Saudi Aramco, Dhahran, Saudi Arabia) | Almuaibid, A. (Saudi Aramco, Dhahran, Saudi Arabia) | Ayirala, S. (Saudi Aramco, Dhahran, Saudi Arabia) | Qasim, A. (Saudi Aramco, Dhahran, Saudi Arabia) | Yousef, A. (Saudi Aramco, Dhahran, Saudi Arabia)
Abstract The occurrence of water blockage is a major concern for gas wells, which severely impacts the productivity. This phenomenon is due to the prolonged contact of surrounding region around wellbore with water thereby increasing the water saturation relative to gas saturation. Consequently, the pore spaces are completely occupied with water, blocking the flow of gas and thus reducing the gas production. In this paper, we propose electrical treatment as a potential solution to reverse the unforeseen water blocking process and revive dead gas wells to produce desired gas. Electrical treatment involves the placement of two electrodes in between two spaced wells or within the same well, one acting as source and the other as a sink. One of these electrodes acts as a cathode, while the other as an anode to cover a reservoir region of around 2-3 km. After current is applied from power supply to well head, the charge will propagate through metallic casing along the well until pay zone delivering electric current to the reservoir. The electrical induced effects in the reservoir may vary according to the variation of the current density and voltage applied. The tight and small pore throats will be enlarged by the application of electrical current. This results in an increase of pore throat radius due to motion of water molecules, cations and anions thereby releasing some of the water from blocked pore throats. Thus, permeability and subsequently relative permeability to water is increased. The local energy pulses will also cause partial electrolysis forming gas droplets besides enhancing the coalescence of released water droplets to form larger water ganglia. These larger water ganglia will sequentially grow to form a continuous film of water phase to minimize surface energy and ease the movement of water. The electrical treatment operation can take up to 30 hours with a long-lasting effect from 6 months up to 2-3 years. The electrical treatment method described in this paper to revive dead gas wells is a sustainable and eco-friendly solution for easy practice in the field. This cost-effective approach can prolong the life of gas wells to increase the productivity.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > Texas (0.29)
- North America > Canada > Alberta (0.29)
- North America > United States > California (0.28)
- North America > United States > California > San Joaquin Basin > Cal Canal Field (0.99)
- Asia > Indonesia > Sumatra > Aceh > North Sumatra Basin > B Block > Arun Field (0.99)
- North America > Canada (0.89)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.89)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Estimation of Surface Production Rates in Electrical Submersible Pump Producing Oil Wells by Numerical Iterative Algorithm-Based Models
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Manish, Kumar (Cairn Oil & Gas, Vedanta Ltd) | Chandak, Ravi (Cairn Oil & Gas, Vedanta Ltd) | Chauhan, Shailesh (Cairn Oil & Gas, Vedanta Ltd) | Singhal, Joy (Cairn Oil & Gas, Vedanta Ltd) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd)
Abstract This paper is an addendum to SPE-200174-MS, which explains the deterministic Approach Towards Well Intervention Candidate Selection & quantification of Parameters in ESP & Jet Pump Wells. The purpose of this paper is to quantify liquid rates in ESP producer wells by estimating the hidden parameter which directly impacts the system production rates. These hidden parameters are the tubing inner wall deposition, deposition inside pumps leading to pump head reduction. These hidden variables make simple well modelling software production rate calculations incorrect. This paper describes facts related to the verification of the output model liquid rates with genuinely observed rates by surface well test units and calibrated multiphase flow meter which makes the overall modelling valid and correct. In ESP wells, the input parameters required by the model is pump intake pressure, pump discharge pressure, pump running frequency and surface THP which are generally available. The models described in SPE-200174-MS for ESP & Jet pump wells can compute 3 variables for 3 set of equations. This model gives surface liquid rates, tubing wall deposition, ESP pump wear (deposition inside pump). Other input parameters required in the model to run the iterations are well water cut, GOR (Gas to oil ratio), productivity index, and reservoir pressure. These models calculate surface production rates for well rates allocation & support in monitoring various wells performance. Its results have been verified by various surface well test units & calibrated multiphase flow meters. There are many advantages of this algorithm such as - Prediction & calibration of MPFMs (Multiphase flow meter data) at well pads, tubing deposition estimation (assists in planning of tubing scraping jobs by slickline unit, Coil tubing roto-jet wellbore cleanout or motor assisted scraper jobs in flowing well), ESP pumps wear estimation (assist in planning ESP wear treatment by chemical soaking/mechanical flushing operations). This paper gives a new approach for ESP wells production rates determination. It mentions various factors which affects the liquid rate of wells. Production restoration candidates are very easily identified using this model. This can be very useful where well testing frequency is less, well pad MPFM is not installed, or where there are frequent issues in MPFM. This work assists in determining various important parameters to monitor oil producer wells with electric submersible pump (ESP). The problems are associated to the fields that contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. It was observed that formation oil to water flooding had adverse mobility ratio and improve sweep efficiency, polymer flooding was adopted. As the Polymer flooding proceeded, polymer breakthrough in producer wells was observed. The major challenges faced in producer wells are polymer & scale depositions. This issue has surfaced in field due to polymer breakthrough in oil producers and mixing of produced polymer concentration in well fluid with scales, wax, or other bivalent ions. Major concerns due to polymer deposition included, fouling of artificial lift system, decrease of well uptime, ESP efficiency decrease. ESP is the major artificial lifts for the field, the surface liquid rate is one of the most important parameters which can address production decrease which may have been caused by any reason. Thus, a necessity was felt to address the issue by empirical based modelling which can quantify the same. The developed models are helpful and determines various surface liquid rate and other critical causal parameters in ESP well.
- North America > United States > Texas (0.68)
- Asia > India > Rajasthan (0.47)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
Abstract Smart Liners rely on the limited-entry principle where a number of small holes act to distribute acid along the un-cemented reservoir section. Over the past two years, this technique has become a key method for matrix-acid stimulation of ADNOC's carbonate reservoirs. The objective of this paper is to summarize the learnings from more than 100 deployments and tie together the key elements of the hole spacing design, the stimulation job execution, and the performance monitoring. A software algorithm generates the hole spacing design to honor a predefined acid flow distribution along the drain length. Quantification of the stimulation efficiency is addressed in several ways. First, the baseline well performance is established with production tests covering several months and in some cases accompanied by a pre-stimulation production logging test (PLT). The stimulation job is then analyzed and compared against a wormhole model to derive the transient injectivity improvement versus acid volume pumped. After the stimulation, the stabilized performance is analyzed in terms of production testing and occasionally a pressure buildup survey and a PLT. Results have so far been very encouraging. Smart Liners have been deployed predominantly in oil producers and water injectors but a few implementations have targeted tight gas reservoirs. A typical steady-state productivity gain is 100-150% above the baseline unstimulated well and the technique consistently outperforms conventional matrix-acid stimulation techniques. The post-stimulation PLT's show that the entire wellbore contributes to flow, even in extended-reach wells. The majority of the efficiency improvement seems to occur with an acid coverage of 0.5 bbl/ft but some wells benefit from higher acid dosages. A wormhole model developed specifically for this completion-stimulation method can reproduce the observations and helps guide designs of future stimula0tion jobs by suggesting modifications to the hole spacing, which will improve the performance improvement using less acid volume.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.21)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- Asia > Middle East > Turkey > Selmo Field (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Al Shaheen Field > Shuaiba Formation (0.99)
- (9 more...)
Dynamic Fracture Characterization Using Multiphase Rate Transient Analysis of Flowback and Production Data
Zhang, Zhengxin (China University of Petroleum Beijing) | Sun, Guoqing (Northeast Petroleum University) | Zhou, Xingze (PetroChina Changqing Oilfield Company) | Dang, Kaiyan (Shaanxi YanChang Petroleum Group Co., Ltd.) | Su, Xing (Pennsylvania State University)
Abstract This study presented a comprehensive method for characterizing reservoir properties and hydraulic fracture (HF) closure dynamics using the Rate Transient Analysis (RTA) of flowback and production data. The proposed method includes straight-line analysis (SLA), type-curve analysis (TCA), and model history matching (MHM), which are developed for scenarios of two-phase flow in fracture, stimulated reservoir volume (SRV), and NSRV domains. HF closure dynamics are characterized by two key parameters: pressure-dependent permeability and porosity controlled by fracture permeability-modulus and compressibility. The above techniques are combined into a generalized workflow to iteratively estimate the five parameters (four optional parameters and one fixed parameter) by reconciling data in different domains of time (single-phase water flow, two-phase flow, and hydrocarbon-dominated flow), analysis methods (SLA, TCA, MHM), and phases (water and hydrocarbon phase). We used flowback and production data from a shale gas well in the US to verify the practicability of the method. The analysis results of the field cases confirm the good performance of the newly developed comprehensive method and verify the accuracy in estimating the static fracture properties (initial fracture pore volume and permeability) and the HF dynamic parameters using the proposed generalized workflow. The accurate prediction of the decreasing fracture permeability and porosity, fracture permeability-modulus, and compressibility demonstrates the applicability of the workflow in quantifying HF dynamics. The field application results suggest a reduction of the fracture pore volume by 30%, and a reduction of the fracture permeability by 98% for shale gas well. Instead of a single analysis method for RTA, this paper proposed a comprehensive analysis method that includes SLA, TCA, and MHM. The interpretation results of the three analysis methods are mutually constrained, which can reduce the non-uniqueness problem of inversion. Compared with the others fracture characterization workflow that need fixed input and output parameters. This proposes general workflow not only completely characterizes the fracture closure dynamics but also can select the unknown parameters (to be determined) according to the actual scenarios of a well and the demands of reservoir engineers.
- Asia (1.00)
- North America > United States (0.89)
- North America > Canada > Alberta (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (8 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (3 more...)
Enabling Well Landing Decision with Fluid Mapping While Drilling
Zulkipli, Siti Najmi Farhan (PETRONAS Carigali Sdn Bhd) | Hendrawati, May Sari Maysari (PETRONAS Carigali Sdn Bhd) | Lowrans, Calvin (PETRONAS Carigali Sdn Bhd) | Tan Jeng Yen, Philip (PETRONAS Carigali Sdn Bhd) | Garcia Mayans, Aldrick (SLB) | Liu, Chunlin Forrest (SLB)
Abstract Geosteering and reservoir mapping from deep resistivity and acoustic measurements have revolutionized the drilling industry. Looking around, ahead, and aside information allows for optimal well placement in complex reservoir structures, while drilling increasingly difficult well trajectories. Downhole fluid analysis (DFA) while drilling, aka fluid mapping while drilling (FMWD), can make geosteering even more powerful by incorporating actual InSitu fluid information into landing and geosteering decisions. This paper looks at successful FMWD based well placement made in a Malaysian field. Field XYZ is a prolific oilfield with a strong gas cap and moderate water drive. The operator has planned a new greenfield campaign to boost declining production by drilling new horizontal oil producers from the existing well centers. The Late Oligocene - Miocene sandstones are well known homogenous units. However, salinity, resistivity contrast, and long transition in the swept zone become a major challenge. Active production, gas cap, aquifer movement, pressure depletion and complex porosity and permeability distribution cause uncertainties on the actual fluid contacts. Fluid typing from petrophysical measurements is inconclusive. Modelling for reservoir mapping resistivity-based measurements highlighted the challenges to land the wells in the thin oil pay zone with degrading rock quality at the bottom and uncertain OWC depth. The operator decided to drill a pilot section through the reservoir sequence to acquire critical subsurface data, identify actual fluid contacts and set the appropriate landing point. An FMWD service was integrated in the bottomhole assembly to provide a comprehensive reservoir fluid characterization. Eight (8) acquisitions have been performed. Before acquiring DFA stations the initial program called to draw fluid gradients from pretests. This method turned to be misleading and inconclusive due to limited reservoir thickness, variable permeabilities and depletion. It was changed to a more extensive DFA acquisition with less reliance on pressure-based gradients. Differential sticking is a major historical risk due to active production. A new operational workflow was engineered to mitigate this risk. Conventional long pump-outs were fragmented into a set of repeat shorter ones at same depths within a stationary time limit set by drilling. Fluid characterization was thereby safely and efficiently performed by ensuring proper control of borehole stickiness with no stuck pipe event or excessive overpull, and without compromising the formation evaluation objectives or clean-up process. Acquired fluid information in the sand sequence provided new insights of the fluid distribution and contacts, yielding increased accuracy on the landing position of the production sections, and well producibility. While still mostly perceived as an exploration/appraisal formation evaluation technique, FMWD is a powerful and disruptive geosteering solution. The combination of InSitu and while-drilling fluid, petrophysical and producibility data allows optimal positioning of wellbores, eventually yielding increased reservoir drainage.
- Asia (1.00)
- North America > United States > Texas (0.55)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block P 9 > Bekok Field (0.99)
- Africa > Tanzania > Indian Ocean > K Formation (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (6 more...)
Semut Field Enhancing Production: Integrated Analysis to Reveal Thin Layer in Thick Sand Formation on Brown Waterflooded Field
Evelyn, Katerina (PT. Pertamina Hulu Rokan) | Ustiawan, Arief Budiman (PT. Pertamina Hulu Rokan) | Ramadhani, Urfi (PT. Pertamina Hulu Rokan) | Moestopo, Hendar Soeharnoko (PT. Pertamina Hulu Rokan) | Masyhuri, Ali (PT. Pertamina Hulu Rokan) | Afton, Muhammad (PT. Pertamina Hulu Rokan) | Fardiansyah, Iqbal (PT. Pertamina Hulu Rokan)
Abstract Semut Field is a small brown field located in Central Sumatra basin produced since 1966 and waterflooded since 2009. Semut Field production has already depleted at 1/10 from its peak production and produced with high water cut. Earlier production strategy had been targeted at waterflooded thick and good permeability (~1 Darcy) reservoir and produced comingle. Deep dive and comprehensive analysis on G&G and rock properties on sand basis will be the answer to reveal any hidden opportunity on mature reservoir to increase oil production in Semut Field. The approach to increase oil production is done by using and analyzing new data from Carbon-Oxygen (CO) logs and new infill well in 2021 to map the unrevealed potential of remaining by-passed oil. This field opportunity is hidden in lower permeability thin sand (<300 mD) with limited distribution that was previously overlooked in wide scale stratigraphic analysis. Comprehensive analysis of high-resolution stratigraphy also could figure out some thin sand that separated from the main sand lobes in each formation. More analysis on historical production and completion of old wells that have thin sand opportunity should be done to find out the earlier sand performance. High-resolution stratigraphy approach analysis by layer sand is proven for revealing hidden opportunity in Semut Field. The remaining oil was found stored in a thin sand layer with perm ~200 mD which is lower than the average overall sand formation permeability. There are two main recommendations to unlock the opportunity at Semut Field based on the analysis result. First, completion strategy by selecting and precising perforation depth is critical since the separation between sand layer could only be between 2-3 ft shale. Second, production strategy by producing single or commingle with other sand that have similar PI and reservoir pressure. This approach gives outstanding results with oil gain 1,600 BOPD and oil cumulative 28 MBO within 1 month production, it is doubling Semut Field production. This effective approach could be an alternative strategy to be applied in other Mature waterflood field or Primary field. This is a good case of how workovers on old wells can increase oil production in cheap way and dramatically extended good economic life.
- Asia > Indonesia > Sumatra (0.76)
- North America > United States > Texas (0.70)
- Asia > Middle East > Israel > Mediterranean Sea (0.25)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.62)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin (0.99)
- Asia > Indonesia > Sumatra > Central Sumatra Basin (0.99)
- North America > United States > Montana > Sumatra Field (0.97)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.91)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- (3 more...)
Investigating Pore Body, Pore Throat, Nano-Pore Wettability Preference in Several Unconventional Kuwaiti Carbonate Reservoirs
Al-Sayegh, Saleh (University of Missouri Science & Technology & Kuwait Oil Company) | Flori, Ralph E. (University of Missouri Science & Technology) | Alajaj, Hussain (University of Missouri Science & Technology) | Al-Bazzaz, Waleed Hussien (Kuwait Institute for Scientific Research)
Abstract This study will investigate measuring the wettability contact angles of native unconventional tight carbonate as well as other unconventional pore system reservoir samples that hosts varied pore shapes and subsequent wettability contact angle distributions in both reservoir matrix and possible natural fractures. Also, the investigation will include validation of the grain/ pore-wall wettability regions and classify the natural wettability preference available inside pores of the rock and their overall wettability performance and recovery efficiency contributions. Further investigation will include modeling pore throat contact angle wettability, and to understand their new physics that will advance reservoir characterization and oil recovery improvement.
- Asia > Middle East > Kuwait (0.71)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.71)
- Oceania > New Zealand > North Island > Tasman Sea > Taranaki Basin > Maui Field (0.99)
- Oceania > New Zealand > North Island > Taranaki Basin (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
Developing Consistent Relative Permeability and Capillary Pressure Models for Reservoir Simulation of CCS Projects
Lun, L. S. (ExxonMobil Technology and Engineering Company, Spring, TX, USA) | Gao, B. (ExxonMobil Upstream Company, Spring, TX, USA) | Krishnamurthy, P. (ExxonMobil Technology and Engineering Company, Spring, TX, USA) | Kohli, K. (ExxonMobil Services & Technology Private Limited, Bangalore, Kamataka, India) | Wattenbarger, R. C. (ExxonMobil Upstream Integrated Services, Spring, TX, USA)
Abstract With the need for rapid growth of the CCS industry, practitioners will need to rely on modeling and simulation, rather than analogs, to further understanding. We cannot solely rely on the results from the handful of small CCS projects around the world as the subsurface characterization of these projects have not necessarily been worked to the same rigor as major oil and gas assets. Furthermore, new practitioners are entering the space who may not be as steeped in subsurface knowledge and development experience as oil and gas professionals. We decided, given our history and leadership in both special core analysis (SCAL) and reservoir simulation to aid in developing and managing major subsurface projects, that we are in a unique position to give guidance to the CCS industry in this nascent phase. Presented here are a workflow to generate simulation-ready saturation function inputs (relative permeability and capillary pressure) curves and guidance on expected ranges for Corey parameters. We show that inputting measured data directly into a reservoir simulator leads to optimistic, underprediction of CO2 plume size during and post-injection, which has consequences to business decisions such as land acquisition, land stewardship and monitoring, measuring, and verification (MMV) plans.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.46)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- Asia > Middle East > Qatar > Arabian Basin > Arabian Gulf Basin > Dukhan Field (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Core analysis techniques have traditionally been used mainly for hydrocarbon reservoir applications. However, the same techniques are equally applicable to reservoir issues associated with energy transition, such as geothermal prospects, carbon geosequestration, and hydrogen storage. Traditionally, much core analysis has been performed successfully using core plugs. However, this approach has certain drawbacks: (1) the selected plugs may not necessarily be representative of the full range of lithologies, (2) key features (e.g., thin naturally cemented or fractured zones) may be missed, (3) high-resolution detail at the lamina scale may be missed, (4) depth shifting to well logs may not be sufficiently accurate, and (5) this strategy may be more sensitive to missing core. In this paper, we highlight the usefulness of probe core analysis techniques on slabbed core and powdered samples. For many reservoirs relevant to energy transition, it is crucial to have a high-resolution continuous record of petrophysical properties so that key features are not missed. Probe measurements are less destructive, without the need to cut core plugs, and provide: (1) high-resolution data at the lamina scale so that key features and small-scale heterogeneities can be identified, (2) improved depth matching to well-log data, and (3) rapid, cost-effective data. We describe examples highlighting some different probe techniques. While some techniques are well known, such as probe permeability, others, such as probe acoustics, probe luminance (from linear X-ray measurements), and probe magnetics, are less familiar to core analysts but are well suited for analyzing cores from reservoirs associated with energy transition as well as hydrocarbons. For example, potential geothermal prospects involve studying igneous and metamorphic samples (where the main radiogenic heat sources reside) as well as sedimentary samples, and differences in the magnetic susceptibility signals using a small, portable magnetic probe can quickly differentiate the different rock types. Probe acoustics can be used to (1) rapidly identify anisotropy by orienting the acoustic transmitter-receiver bracket in different directions, (2) identify open microfractures via longer transit times, and (3) produce high-resolution porosity profiles after correlation of transit times with some representative plug or well-log porosity data. Probe luminance and associated linear X-ray images, which are related to density, can indicate small-scale heterogeneities that may impact permeability variation and anisotropy and may not be seen from mere visual observations of the slabbed core surface.
- North America > United States (1.00)
- North America > Canada > Alberta (0.69)
- Europe > Norway (0.68)
- Asia > Middle East (0.68)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geophysics > Magnetic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Rannoch Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > NOAKA Project > Krafla North Prospect > Etive Formation (0.98)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)