Integration of Downhole Fluid Analysis and Advanced Mud Gas Logging Reduces Uncertainty in Reservoir Evaluation

Kyi, Ko Ko; Lynn, Cheam Syeh; Haddad, Sammy; Chouya, Smail; Wa, Wee Wee; Gligorijevic, Aleksandar

doi:10.2523/iptc-17485-ms

All Days 2014

DOI: 10.2523/iptc-17485-ms

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Integration of Downhole Fluid Analysis and Advanced Mud Gas Logging Reduces Uncertainty in Reservoir Evaluation

Ko Ko Kyi

Cheam Syeh Lynn

Sammy Haddad

et al.

Abstract: Reservoir fluid characterization is crucial for the success of field exploration and development phases. Early detection of hydrocarbon allows accurate determination of reservoir fluid properties and plays a key role in reducing uncertainty in reservoir evaluation and future field development strategies. Advanced Mud Gas logging (AMG) system and wireline downhole fluid analysis are among the important means available in the oil and gas industry for such analyses. Each method has its limitations and advantages,… Show more

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Formation Evaluation in Tight Clastic and Carbonate Formations: A Malay Basin Case Study

Kyi

Haddad

Chouya

et al. 2015

Day 1 Mon, September 14, 2015

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Tight heterogeneous clastic and carbonate formations present great challenges in terms of reservoir fluid characterisation and downhole fluid sampling during exploration phase. The low mobility imposed by the tight clastic formations usually prohibits conclusive formation testing and sampling using conventional wireline formation testers (WFT) with single probe. The small flow area provided by single probe typically does not allow single phase reservoir fluid withdrawal in such low mobility environment due to the high pressure drawdown. In addition, the optimisation of pressure drawdown is critical to ensure single phase and representative downhole reservoir fluid sampling within the allowed station time. On the other side, the heterogeneous nature of the carbonate pore system imposes a significant mobility range, varying from very tight to good permeability intervals. Pinnacle reef carbonates are often naturally fractured. The natural fracture system may cause fluid losses resulting in drilling and data acquisition challenges. Detailed planning and careful consideration on various testing options available is needed to address this high mobility variation and subsequently to maximise the data acquisition at minimum operation cost, time and risks. This work presents case studies demonstrating a new WFT approach in appraising tight laminated sandstone and carbonate reservoirs in offshore Malaysia fields. An initial attempt with conventional technology did not allow to obtain any conclusive formation pressure measurement, pressure gradients, downhole reservoir fluid identification and sampling. On the other hand, the application of WFT Dual Packer offers limited pressure drawdown range and requires extended station time usually resisted by drillers. Realising the importance of these exploration wells to verify potential reserves from initial geological and petrophysical data, it became crucial to search for an alternative technology to achieve the fluid evaluation objectives in a time-effective manner. This paper presents a new approach and methodology that was implemented and resulted in reliable reservoir rock pressure, mobility, and sampling while improving operational efficiency. As a result, it was possible to successfully evaluate the reservoirs of interest and meet study objectives. This work will also provide a proposed best practice, workflow, and recommendations supported by field data examples.

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Formation Evaluation in Tight Clastic and Carbonate Formations: A Malay Basin Case Study

Kyi

Haddad

Chouya

et al. 2015

Day 1 Mon, September 14, 2015

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Real-Time Quantitative Composition of Formation Fluids While Drilling

Colombel

Guerriero

Ringer

2018

IADC/SPE Drilling Conference and Exhibition

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Mud-gas technologies for continuous PVT-like analysis of reservoir fluids in the drilling mud require a calibration procedure to determine the efficiency of the gas extraction process. This procedure is required because the efficiency of the hydrocarbons extraction process is strongly affected by the drilling mud type and properties, and so it must be performed any time the mud significantly changes. The calibration procedure requires a sample of drilling mud that contains significant amounts of alkanes. Currently, this sample is collected while drilling during a gas peak and stored until the end of the phase, when the calibration can be performed. Thus, the gas extraction efficiency can only be determined at the end of each drilled section, and the quantitative analysis of the reservoir fluid in the mud is made available only at the end of each section. This paper presents a new procedure, in which a Calibration Mud sample is built by injecting and emulsifying several alkanes into the mud. The calibration can then be performed at any time before drilling commences. It is extremely difficult to inject and dissolve gaseous light hydrocarbons into a mud sample at the rigsite. For this reason, we inject a sample of six liquid alkanes into the mud and emulsify it to build a mud sample suitable for the calibration procedure. The extraction efficiencies for the lighter gas alkanes are then extrapolated from those of the injected alkanes using a model of the extraction process. The new calibration process has been tested in several wells around the world. In each test, the new calibration process and standard calibration (performed at the end of the phase using mud collected while drilling) were performed. Validation of the new technique comes from ensuring the extraction efficiency coefficients using our new calibration mud match those coming from the standard calibration. The results were conclusive with similar coefficients obtained in each test. The uncertainty intervals overlap, and the calibration coefficients are statistically equivalent. The new calibration procedure represents an innovative methodology enabling real-time, continuous quantification of the light hydrocarbons content (C1-C6) of the reservoir fluid, comparable to the PVT monophasic composition, while drilling, at surface. This is the first time that such data can be delivered in real-time while drilling. The resulting measurements have multiple applications such as enhanced geosteering and well placement, real-time identification of gas-oil contacts, and real-time selection of sampling points and can be integrated with downhole tool measurements to provide a true real-time understanding of the subsurface fluids.

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Real Time Reservoir Fluid Log from Advanced Mud Gas Data

Arief

Yang

2020

SPE Annual Technical Conference and Exhibition

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In a recent paper (Yang et al., 2019a), we published a machine learning method to quantitatively predict reservoir fluid properties from advanced mud gas (AMG) data. This approach has clear advantages due to early access, low cost, and a continuous reservoir fluid prediction for all reservoir zones. In this paper, we demonstrate how real time reservoir fluid logs are generated and compare the results with PVT samples or production data from the same well. We develop a workflow of generating reservoir fluid logs from AMG data and PVT database. The workflow consists of two main processes; first a quality assessment of AMG data and second the computation of reservoir fluid properties (in this paper we use gas oil ratio). The entire workflow is written in python and embedded into existing commercial petrophysics softwares. The final product of the workflow are three log tracks which we call the reservoir fluid logs and those are 1) the concentration readings of the AMG data, 2) the QC metric score, and 3) the predicted GOR log. These three logs are plotted together with other standard open hole logs such as gamma ray, neutron-density, sonic and resistivity log to get a more comprehensive formation evaluation. Reservoir fluid logs derived from AMG data has two main advantages. First, it is the only approach to acquire continuous reservoir fluid properties along the well path. The continuous fluid profile can be used to understand the variation of reservoir fluids in both vertical and lateral direction. The second advantage is that the reservoir fluid log is obtained while drilling and therefore the information can be used to optimize the drilling process or the downhole sampling program during wireline operation. In this paper, we demonstrate the application of the reservoir fluid logs in four conventional field cases. In the first study case we show the benefit of using the reservoir fluid logs in a horizontal well as a substitute for downhole fluid sampling. In the second case study, we demonstrate how the reservoir fluid log is utilized to optimize the downhole fluid sampling program which results in reducing the subsurface uncertainty. Next, we exhibit the use of the reservoir fluid logs to locate gas oil contact in a case where pressure data does not show clear distinction of gas and oil gradient in the reservoir. In the last example, we illustrate the use of reservoir fluid knowledge from AMG to characterizing the fluid variation across a field. The field applications demonstrate the success of the new method for conventional reservoirs, provided good-quality AMG data are available.

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Integration of Downhole Fluid Analysis and Advanced Mud Gas Logging Reduces Uncertainty in Reservoir Evaluation

Cited by 4 publications

References 0 publications

Formation Evaluation in Tight Clastic and Carbonate Formations: A Malay Basin Case Study

Formation Evaluation in Tight Clastic and Carbonate Formations: A Malay Basin Case Study

Real-Time Quantitative Composition of Formation Fluids While Drilling

Real Time Reservoir Fluid Log from Advanced Mud Gas Data

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