A Type-Curve-Based Spreadsheet Program for History Matching and Forecasting Tight-Gas Production

2001 ◽  
Author(s):  
Juan D. Munoz ◽  
Her-Yuan Chen ◽  
Lawrence W. Teufel
Keyword(s):  
History Matching ◽  
Gas Production ◽  
Tight Gas ◽  
Type Curve ◽  
Spreadsheet Program

Natural fractures in tight gas sandstones: a case study of the Upper Triassic Xujiahe Formation in Xinchang gas field, Western Sichuan Basin, China

2021 ◽  
pp. 1-18
Author(s):  
Yunzhao Zhang ◽  
Lianbo Zeng ◽  
Wenya Lyu ◽  
Dongsheng Sun ◽  
Shuangquan Chen ◽  
...  
Keyword(s):  
Production Capacity ◽  
Gas Production ◽  
Upper Triassic ◽  
Tight Gas ◽  
Natural Fractures ◽  
Carbon And Oxygen Isotopes ◽  
Gas Field ◽  
Xujiahe Formation ◽  
Western Sichuan ◽  
Tight Gas Reservoir

Abstract The Upper Triassic Xujiahe Formation is a typical tight gas reservoir in which natural fractures determine the migration, accumulation and production capacity of tight gas. In this study, we focused on the influences of natural fractures on the tight gas migration and production. We clarified characteristics and attributes (i.e. dips, apertures, filling degree and cross-cutting relationships) of the fractures based on image logging interpretations and core descriptions. Previous studies of electron spin resonance, carbon and oxygen isotopes, homogenization temperature of fluid inclusions analysis and basin simulation were considered. This study also analysed the fracture sequences, source of fracture fillings, diagenetic sequences and tight gas enrichment stages. We obtained insight into the relationship between fracture evolution and hydrocarbon charging, particularly the effect of the apertures and intensity of natural fractures on tight gas production. We reveal that the bedding fractures are short horizontal migration channels of tight gas. The tectonic fractures with middle, high and nearly vertical angles are beneficial to tight gas vertical migration. The apertures of fractures are controlled by the direction of maximum principal stress and fracture angle. The initial gas production of the vertical wells presents a positive correlation with the fracture abundance, and the intensity and aperture of fractures are the fundamental factors that determine the tight gas production. With these findings, this study is expected to guide the future exploration and development of tight gas with similar geological backgrounds.

scholarly journals Unconventional Gas Production from Hydraulically Fractured Well-An Application of Direct Search Based Optimization Algorithm

2019 ◽  
Vol 8 (2S11) ◽  
pp. 2726-2737
Keyword(s):  
Objective Function ◽  
Fracture Propagation ◽  
Gas Production ◽  
Production Model ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Unconventional Gas ◽  
Fracture Geometry ◽  
Propagation Behavior ◽  
Fractured Well

Unconventional gas reservoirs are now the targets for meeting the demand for gas. These reservoirs are at the depth of more than 10,000 ft (even over 15000 depth as well) and are difficult to be exploited by conventional methods. For the last decades hydraulic fracturing has become the tool to develop these resources. Mathematical models (2D and pseudo-3D) have been developed for fracture geometry, which should be realistically created at the depth by surface controllable treatment parameters. If the reservoir rock is sandstone, then proppant fracturing is suitable and if the rock is carbonates, then acid fracturing is applicable. In both cases, proper design of controllable treatment parameters within constraints is essential. This needs proper optimization model which gives real controllable parametric vales. The model needs the most important analyses from geomechanical study and linear elastic fracture mechanics of rock containing unconventional gas so that fracture geometry makes maximum contact with the reservoirs for maximum recovery. Currently available software may lack proper optimization scheme containing geomechanical stress model, fracture geometry, natural fracture interactions, real field constraints and proper reservoir engineering model of unconventional gas resources, that is, production model from hydraulically fractured well (vertical and horizontal). An optimization algorithm has been developed to integrate all the modules, as mentioned above, controllable parameters, field constraints and production model with an objective function of maximum production (with or without minimization of treatment cost). Optimization is basically developed based on Direct Search Genetic and Polytope algorithm, which can handle dual objective function, non-differentiable equations, discontinuity and non-linearity. A dual objective function will meet operator’s economic requirements and investigate conflict between two objectives. The integrated model can be applied to a vertical or horizontal well in tight gas or ultra-tight shale gas deeper than over 10,000 ft. A simulation (with industrial simulators) was conducted to investigate and analyse fracture propagation behavior, under varying parameters with respect to the fracture design process, for tight gas reservoirs. Results indicate that hydraulic fracture propagation behavior is not uninhibited in deep reservoirs as some may believe that minor variations of variables such as in-situ stress, fluid properties etc. are often detrimental to fracture propagation in some conditions. Application of this model to a hypothetical tight and ultra-tight unconventional gas formations indicates a significant gas production at lower treatment cost; whereas the resources do not flow without any stimulation (hydraulic fracturing).

scholarly journals Development of machine learning predictive models for history matching tight gas carbonate reservoir production profiles

2018 ◽  
Vol 15 (5) ◽  
pp. 2235-2251 ◽  
Author(s):  
Eric Thompson Brantson ◽  
Binshan Ju ◽  
Busayo Oreoluwa Omisore ◽  
Dan Wu ◽  
Aphu Elvis Selase ◽  
...  
Keyword(s):  
Machine Learning ◽  
Predictive Models ◽  
History Matching ◽  
Carbonate Reservoir ◽  
Tight Gas

Advanced Well Completion Strategies to Improve Gas Production Deliverability in Marginal Tight Gas Reservoirs from an Onshore Abu Dhabi Gas Field

2021 ◽  
Author(s):  
Hajar Ali Abdulla Al Shehhi ◽  
Bondan Bernadi ◽  
Alia Belal Zuwaid Belal Al Shamsi ◽  
Shamma Jasem Al Hammadi ◽  
Fatima Omar Alawadhi ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
Gas Production ◽  
Abu Dhabi ◽  
Tight Gas ◽  
Production Rates ◽  
Well Productivity ◽  
Gas Saturation ◽  
Well Design ◽  
The Impact

Abstract Reservoir X is a marginal tight gas condensate reservoir located in Abu Dhabi with permeability of less than 0.05 mD. The field was conventionally developed with a few single horizontal wells, though sharp production decline was observed due to rapid pressure depletion. This study investigates the impact of converting the existing single horizontal wells into single long horizontal, dual laterals, triple laterals, fishbone design and hydraulic fracturing in improving well productivity. The existing wells design modifications were planned using a near reservoir simulator. The study evaluated the impact of length, trajectory, number of laterals and perforation intervals. For Single, dual, and triple lateral wells, additional simulation study with hydraulic fracturing was carried out. To evaluate and obtain effective comparisons, sector models with LGR was built to improve the simulation accuracy in areas near the wellbore. The study conducted a detailed investigation into the impact of various well designs on the well productivity. It was observed that maximizing the reservoir contact and targeting areas with high gas saturation led to significant increase in the well productivity. The simulation results revealed that longer laterals led to higher gas production rates. Dual lateral wells showed improved productivity when compared to single lateral wells. This incremental gain in the production was attributed to increased contact with the reservoir. The triple lateral well design yielded higher productivity compared to single and dual lateral wells. Hydraulic fracturing for single, dual, and triple lateral wells showed significant improvement in the gas production rates and reduced condensate banking near the wellbore. A detailed investigation into the fishbone design was carried out, this involved running sensitivity runs by varying the number of branches. Fishbone design showed considerable increment in production when compared to other well designs This paper demonstrates that increasing the reservoir contact and targeting specific areas of the reservoir with high gas saturation can lead to significant increase in the well productivity. The study also reveals that having longer and multiple laterals in the well leads to higher production rates. Hydraulic fracturing led to higher production gains. Fishbone well design with its multiple branches showed the most production again when compared to other well designs.

Comparison of Simplistic and Geologically Descriptive Production Modeling for Natural-Gas Hydrate by Depressurization

SPE Journal ◽  
2019 ◽  
Vol 24 (02) ◽  
pp. 563-578 ◽  
Author(s):  
Yilong Yuan ◽  
Tianfu Xu ◽  
Yingli Xia ◽  
Xin Xin
Keyword(s):  
Gas Hydrate ◽  
History Matching ◽  
Nankai Trough ◽  
Flow Behavior ◽  
Test Site ◽  
Gas Production ◽  
Production Test ◽  
Hydrate Reservoir ◽  
Hydrate Saturation ◽  
Production Modeling

Summary Marine-gas-hydrate-drilling exploration at the Eastern Nankai Trough of Japan revealed the variable distribution of hydrate accumulations, which are composed of alternating beds of sand, silt, and clay in sediments, with vertically varying porosity, permeability, and hydrate saturation. The main purposes of this work are to evaluate gas productivity and identify the multiphase-flow behavior from the sedimentary-complex hydrate reservoir by depressurization through a conventional vertical well. We first established a history-matching model by incorporating the available geological data at the offshore-production test site in the Eastern Nankai Trough. The reservoir model was validated by matching the fluid-flow rates at a production well and temperature changes at a monitoring well during a field test. The modeling results indicate that the hydrate-dissociation zone is strongly affected by the reservoir heterogeneity and shows a unique dissociation front. The gas-production rate is expected to increase with time and reach the considerable value of 3.6 × 104 std m3/d as a result of the significant expansion of the dissociation zone. The numerical model, using a simplified description of porosity, permeability, and hydrate saturation, leads to significant underestimation of gas productivity from the sedimentary-complex hydrate reservoir. The results also suggest that the interbedded-hydrate-occurrence systems might be a better candidate for methane (CH4) gas extraction than the massive hydrate reservoirs.

Geologic Controls on Gas Production and Hydraulic-Fracturing Flowback in Tight Gas Sandstones of the Late Jurassic Monteith Formation, Deep Basin, Alberta, Canada

2016 ◽  
Vol 19 (01) ◽  
pp. 024-040 ◽  
Author(s):  
Liliana Zambrano ◽  
Per K. Pedersen ◽  
Roberto Aguilera
Keyword(s):  
Hydraulic Fracturing ◽  
Gas Production ◽  
Production Performance ◽  
Rock Properties ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Deep Basin ◽  
Rock Types ◽  
Sandstone Reservoirs ◽  
Geologic Controls

Summary A comparison of rock properties integrated with production performance and hydraulic-fracturing flowback (FB) of the uppermost lithostratigraphic “Monteith A” and the lowermost portion “Monteith C” of the Monteith Formation in the Western Canada Sedimentary Basin (WCSB) in Alberta is carried out with the use of existing producing gas wells. The analyses are targeted to understand the major geologic controls that differentiate the two tight gas sandstone reservoirs. This study consists of basic analytical tools available for geological characterization of tight gas reservoirs that is based on the identification and comparison of different rock types such as depositional, petrographic, and hydraulic for each lithostratigraphic unit of the Monteith Formation. As these low-matrix-permeability sandstone reservoirs were subjected to intense post-depositional diagenesis, a comparison of the various rock types allows the generation of more-accurate reservoir description, and a better understanding of the key geologic characteristics that control gas-production potential and possible impact on hydraulic-fracturing FB. Well performance and FB were the focus of many previous simulation and geochemical studies. In contrast, we find that an adequate understanding of the rocks hosting hydraulic fractures is a necessary complement to those studies for estimating FB times. This understanding was lacking in some previous studies. As a result, a new method is proposed on the basis of a crossplot of cumulative gas production vs. square root of time for estimating FB time. It is concluded that the “Monteith A” unit has better rock quality than the “Monteith C” unit because of less-heterogeneous reservoir geometry, less-complex mineralogical composition, and larger pore-throat apertures.

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