Study Compares Fluid-Tracking-Modeling Approaches for Mature Onshore Field

2021 ◽  
Vol 73 (09) ◽  
pp. 41-42
Author(s):  
Chris Carpenter
Keyword(s):  
Gas Injection ◽  
Oil Production ◽  
Detailed Comparison ◽  
Abu Dhabi ◽  
Co2 Injection ◽  
Full Field ◽  
Field Level ◽  
Carbon Dioxide Co2 ◽  
Oil Rim ◽  
Reservoir Simulator

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202747, “Fluid-Tracking Modeling for Condensate/Oil Production and Gas Use Allocation: An Abu Dhabi Onshore Example,” by Yun Wang and Gary Jerauld, SPE, BP, and Yatindra Bhushan, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. A reservoir in a giant field onshore Abu Dhabi has been producing for 6 decades. The reservoir was already saturated at the time of production commencement, with a large oil rim and a gas cap. This paper presents a comprehensive comparison of two modeling-based approaches of fluid tracking for condensate allocation and gas usage: a tracer modeling option in a commercial reservoir simulator and a full-component fluid-tracking approach. Introduction Examples of benchmarking fluid-tracking options against an independent fluid-tracking approach are rare in the literature. The goal of this paper, therefore, is to document a comprehensive and detailed comparison between the fluid-tracking option (TRACK) in NEXUS (a commercial reservoir simulator used by companies of the coauthors of this paper) and a full-component fluid-tracking (FCFT) approach. This work is motivated by the commercial arrangement of a concession covering an onshore field in Abu Dhabi. Because of different equity entitlements among the shareholders for the oil rim and gas cap per the concession commercial terms, a need exists to allocate the condensate vs. oil-rim oil production and the injected lean-gas usage. FCFT The idea of FCFT is relatively straightforward. Before discussing the approach, it is important to note that the focus of this paper is to compare the modeling of different tracking approaches. It is assumed that a fit-for-purpose fully compositional reservoir simulation model already exists. For fluid-tracking modeling with a full-field model (FFM), this means that the compositional reservoir model has already been history matched properly at both field and individual well levels and that no additional reconciliation is required before the hydrocarbon liquid and vapor streams are split into tracked substreams. In this paper, FCFT is completed on the field level for the comparison with the TRACK option in NEXUS. One could easily extend the field level tracking to either regional well-group levels or individual well levels. In the case of the onshore reservoir, lean-gas injection has been active during much of the producing history. In future development schemes under consideration, lean-gas injection, carbon dioxide (CO2) injection, and gas lift are all possible scenarios, raising the question of how to treat injected gas components within the FCFT framework. Different approaches exist to handle the injected gas components. One may treat the injected gas components as either the gas-cap components, the oil-rim components, or entirely new components. Lean gas injected in the onshore field example is actually a dry gas, according to the 11-component equation-of-state (EOS) prediction. Thus, the lean gas can be reasonably modeled with only one new component as long as that component replicates the volumetric behavior of the injected lean gas.

Full Field Tertiary Gas Injection in Abk Field Offshore Abu Dhabi

2003 ◽  
Author(s):  
B. Levallois ◽  
E. Bonnin ◽  
G. Joffroy
Keyword(s):  
Gas Injection ◽  
Abu Dhabi ◽  
Full Field

A Comprehensive Study Developing and Maximizing the Recovery of Gas Condensate from a Giant Onshore Abu Dhabi Gas Field Utilizing Advanced Condensate Tracking, Gas Injection and Drilling Strategies in Next-generation Commercial Numerical Simulator

2021 ◽  
Author(s):  
Bondan Bernadi ◽  
Ihab Nabil Mohamed ◽  
Ahmed Mohamed Al Bairaq ◽  
Mariam Ahmed Al Hosani ◽  
Azer Abdullayev ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Gas Condensate ◽  
Drop Out ◽  
Abu Dhabi ◽  
Next Generation ◽  
Gas Field ◽  
Full Field ◽  
Oil Rim ◽  
Numerical Simulator ◽  
Comprehensive Study

Abstract A comprehensive study of a giant onshore Abu Dhabi gas field using a next-generation commercial numerical simulator has been conducted. The objective was to identify the distribution and track the movement of the gas condensate in the reservoir, and to develop strategies to minimize the condensate drop-out and improve condensate recovery from the field. The field contains a large gas cap and an oil rim. We have identified the distribution of the gas condensate throughout the reservoir and were able to track its movement using the advanced fluid tracking option in the simulator. Once the gas condensate drop-out regions in the reservoir are identified, sensitivity runs with localized changes are carried out to improve the recovery from the reservoir. The strategies to mitigate drop-out include adding infill wells, drilling multi-lateral wells, reinjecting CO2 and dry gas into the reservoir, and hydraulic fracturing near the well bore. We were able to track the distribution of the condensate throughout the reservoir and identified key condensate drop-out regions. Adding infill wells improved the recovery of the condensate. Implementing multi-lateral wells also showed improved condensate recovery in the field. Hydraulic fracturing near the wellbore reduced condensate banking near the wellbore. Injecting dry gas improved the condensate recovery by a re-vaporization process where the liquid condensate is absorbed by dry gas. This paper discusses a comprehensive study on tracking the condensate distribution in a giant onshore field using a commercial simulator. The authors have performed a thorough investigation to identify an optimal condensate recovery strategy for the field, by comparing various recovery strategies using the full field reservoir simulation model.

Full Field Reservoir Simulation Study of an Oil Rim in a Field Offshore Abu Dhabi (UAE)

2000 ◽  
Author(s):  
Bruno Decroux ◽  
Medhat El Emam ◽  
Omar Nassar ◽  
Talal Kadada ◽  
Hagop Harakhanian
Keyword(s):  
Simulation Study ◽  
Reservoir Simulation ◽  
Abu Dhabi ◽  
Full Field ◽  
Oil Rim

An Australian first initiative to re-develop the first commercial onshore oilfield into a CO2 miscible-EOR project

2019 ◽  
Vol 59 (1) ◽  
pp. 179
Author(s):  
Stephanie Barakat ◽  
Bob Cook ◽  
Karine D'Amore ◽  
Alberto Diaz ◽  
Andres Bracho
Keyword(s):  
Oil Recovery ◽  
Dynamic Modelling ◽  
Oil Production ◽  
Simulation Modelling ◽  
Oil Field ◽  
Optimal Time ◽  
Successful Implementation ◽  
Full Field ◽  
Execution Phase ◽  
Reservoir Simulator

The Moonie onshore oil field discovered in 1961, was the first commercial oil discovery in Australia. The field was purchased by Bridgeport Energy Limited (BEL) from Santos in late 2015. An Australian first initiative by BEL is to enhance oil production from the field using tertiary recovery CO2 miscible flood to maximise field oil recovery. The process involves an evaluation of well injection strategies for a miscible displacement process using reservoir simulation modelling. In addition, the project jointly addresses community concerns regarding the rise in greenhouse gas emissions by sourcing 60000–120000 tonnes/annum of CO2 from a nearby power station and/or an ethanol plant. Justified by laboratory experiments and reservoir compositional simulations, BEL’s project timeline to implement a CO2-enhanced oil recovery (EOR) pilot could start from 2020 followed by a 2–3-year full field oil production acceleration project if additional CO2 can be sourced. Based on incremental recovery and operational consideration, an injection well in the southern end of the field surrounded by six existing producers has been selected as a pilot flood. Positive indicative economics are achieved by the efficient displacement with CO2 of 8000 scf/bbl of incremental oil. Full field dynamic modelling predicts a further 8% oil recovery factor by injecting 60 Bcf of CO2 over five years, which could store in excess of three million tonnes of CO2. For the pilot, more than 90% of the injected CO2 will remain in the Precipice sandstone reservoir. However, the efficiency and viability of a CO2-EOR project is subject to successful implementation of the miscibility modelling, logistics and injection strategy and uncertainty quantification. To propel the project into the execution phase a fast-multiphase reservoir simulator has been implemented to complete a probabilistic range of results in optimal time.

Comparison of the Impact of Dip and Vertical Transmissibility on Oil Recovery and Carbon Storage Using Water over Gas Injection in the Forest Reserve Field, Trinidad

2014 ◽  
Author(s):  
S. C. Jones ◽  
L. E. Sobers
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Thick Layer ◽  
Oil Production ◽  
Forest Reserve ◽  
Geologic Storage ◽  
Average Porosity ◽  
Shaly Sand ◽  
Carbon Dioxide Co2 ◽  
The Impact

Abstract A combination of geologic carbon dioxide (CO2) sequestration and CO2 enhanced oil recovery (CO2EOR) can address the two of Trinidad and Tobago's energy sector challenges: falling oil production and increasing CO2 emissions. Geologic storage of CO2 in heavy oil reservoirs can increase oil production while injected CO2 is effectively sequestered. Our investigations are based on 225 ft (~69 m) of the unconsolidated Lower Forest sand, average porosity and permeability of 32% and 125 md, respectively, found within the Forest reserve field, Trinidad. The middle section of this sand package contains a 26 ft (8m) thick layer of shaly sand with average permeability 70 md and average porosity 28%. We used reservoir simulations to determine the impact of dip and reduced transmissibility on the performance of the water over gas injection strategy using CO2. From our results we conclude that the reduced vertical transmissibility and dip affects the formation of the oil bank, water underride and the rate of CO2 migration.

Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated With H2S Into Depleted Gas Fields in the Northeast of the Netherlands

SPE Journal ◽  
2014 ◽  
Vol 19 (06) ◽  
pp. 1058-1068 ◽  
Author(s):  
P.. Bolourinejad ◽  
R.. Herber
Keyword(s):  
The Netherlands ◽  
Carbonic Acid ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Geological Time ◽  
Core Samples ◽  
Carbon Dioxide Co2 ◽  
Gas Fields

Summary Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases—CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S—were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl−, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42−). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates, and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and ≤3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.

Evaluation of CO2 Gas Injection For Major Oil Production Fields in Malaysia - Experimental Approach Case Study: Dulang Field

2001 ◽  
Author(s):  
Zahidah Md. Zain ◽  
Nor Idah Kechut ◽  
Ganesan Nadeson ◽  
Noraini Ahmad ◽  
D.M. Anwar Raja
Keyword(s):  
Experimental Approach ◽  
Gas Injection ◽  
Oil Production ◽  
Co2 Gas

A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Saira ◽  
Emmanuel Ajoma ◽  
Furqan Le-Hussain
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Molar Fraction ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Treated Carbon ◽  
Carbon Dioxide Co2 ◽  
And Storage ◽  
Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

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