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Results
ABSTRACT Recent developments in surface logging and the need for sophisticated information on reservoir content and type in the oil industry have led to the availability of real-time advanced fluid solutions assisting in informed decisions while drilling. The objective of this study was to identify possible fluid contacts and acquire PVT quality sample data while drilling Paleozoic formations. This is accomplished by extracting and analysing formation gas from the drilling fluid employing the Advanced Formation Gas Extraction System for formation evaluation with a high-resolution chromatograph. The Advanced Formation Gas Extraction System provided consistent flow and heated mud and maintained constant temperature conditions. Thus, it provided an accurate chromatographic breakdown of the formation gas extracted from the drilling fluid at surface. The chromatograph was able to detect the hydrocarbons from the light to heavy factions, methane (C1) to pentane (C5), and also extended the detection range to include the dominant C6, C7, C8, aromatics and lighter alkenes. Gas ratio analysis of the detected hydrocarbon components enabled us to evaluate the reservoir fluid content and to identify and characterize the formation fluid and possible fluid contacts. The results, validated by correlation and comparison with other data such as wireline logs, well tests and PVT results assisted in the characterization of lithological changes, possible fluid contacts, vertical fluid differentiation in multi-layered intervals, and drill bit metamorphism (thermal cracking) effect. The comparison between surface gas data analysis and PVT data confirms the consistency between the gas show and the corresponding reservoir fluid composition.
- Geology > Rock Type (0.69)
- Geology > Geological Subdiscipline (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.92)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Mud logging / surface measurements (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 > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Information Technology > Architecture > Real Time Systems (0.48)
- Information Technology > Data Science (0.34)
Abstract Geopressured gas reservoirs materialize as a result of a variety of factors, some of which include the rapid compaction of sand/shale sequences and the uplift of sediment layers by a salt intrusion. These gas reservoirs are commonly characterized by a significant drop in formation compressibility owing to the collapse of the rock matrix, and are notorious in the drilling and production industries for the various problems they cause. This paper reviews the retrograde gas condensate production data presented in SPE-2938 (Duggan, 1972) with modern analysis tools to show that gas condensate banking can cause classic material balance analysis to mimic the shape of a geopressured gas reservoir. The condensation of liquid hydrocarbons below the dew-point in a gas reservoir, and the onset of water influx from a leaky fault can complicate the material balance analysis of these reservoirs and may lead to engineers mistakenly classifying them for what they are not. Failure to properly classify a gas reservoir may lead to an incorrect estimation of original gas in place (OGIP). Accurate determination of initial gas in place is of utmost importance in the process of estimating gas reserves. A lower estimation of OGIP or not accounting for condensate banking in low permeability zones may lead to early abandonment of a gas well or significant loss of reserves for an operating company. Results show that proper consideration of the two-phase Z-factor in the material balance calculations calculated via the constant volume depletion test (CVD) leads to a more accurate determination of gas reserves, in addition, the change in formation compressibility is shown to be consolidated sandstone as opposed to geopressured rock matrix. This paper aims to demonstrate a simplified procedure for the flow-after-flow well test of determining the effect of condensate dropout within the vicinity of the wellbore as the flowing bottom-hole pressure (BHP) drops below the dew-point pressure. Two-phase pseudo pressure was calculated from a constant composition expansion (CCE) using Whitson's Method (Whitson, 1983) for condensate banking and measured gas composition. The classical Anderson "L" gas reservoir of the Mobil-David field in South Texas (Duggan, 1972) was chosen as a case study. Implementation of the proposed procedure will serve as an aid to gas reservoir engineers in properly classifying potential gas condensate reservoirs.
- North America > United States > Texas > Nueces County (0.34)
- Asia > Middle East > Israel > Central District (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)
- Geology > Geological Subdiscipline (0.46)
- Geology > Mineral (0.34)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Mobil David Field > Frio Formation (0.99)
- North America > United States > Texas > Frio Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)