Development of Tightly-Coupled Integrated Asset Model For Use in Production Optimization, De-Bottlenecking and Flow Assurance of Multiple Gas Reservoirs

Shale gas reservoir evaluation and production optimization both require geological models. However, currently, shale gas modeling remains relatively conventional and does not reflect the unique characteristics of shale gas reservoirs. Based on a case study of the Fuling shale gas reservoir in China, an integrated geological modeling workflow for shale gas reservoirs is proposed to facilitate its popularization and application and well improved quality and comparability. This workflow involves four types of models: a structure-stratigraphic model, reservoir (matrix) parameter model, natural fracture (NF) model, and hydraulic fracture (HF) model. The modeling strategies used for the four types of models vary due to the uniqueness of shale gas reservoirs. A horizontal-well lithofacies sublayer calibration-based method is employed to build the structure-stratigraphic model. The key to building the reservoir parameter model lies in the joint characterization of shale gas “sweet spots.” The NF models are built at various scales using various methods. Based on the NF models, the HF models are built by extended simulation and microseismic inversion. In the entire workflow, various types of models are built in a certain sequence and mutually constrain one another. In addition, the workflow contains and effectively integrates multisource data. Moreover, the workflow involves multiple model integration processes, which is the key to model quality. The selection and optimization of modeling methods, the innovation and development of modeling algorithms, and the evaluation techniques for model uncertainty are areas where breakthroughs may be possible in the geological modeling of shale gas reservoirs. The workflow allows the complex process of geological modeling of shale gas reservoirs to be more systematic. It is of great significance for a dynamic analysis of reservoir development, from individual wells to the entire gas field, and for optimizing both development schemes and production systems.

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Gas Production Optimization Using Thermodynamics Hydrate Inhibition Flow Assurance Method

10.2118/198842-ms ◽

2019 ◽

Author(s):

Kenechukwu Obiajulu Nwankwo

Keyword(s):

Gas Production ◽

Production Optimization ◽

Flow Assurance

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Production optimization in well-6 of Habiganj gas field, Bangladesh: a prospective application of Nodal analysis approach

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-00908-2 ◽

2020 ◽

Vol 10 (8) ◽

pp. 3557-3568

Author(s):

Md. Shaheen Shah ◽

Md Hafijur Rahaman Khan ◽

Ananna Rahman ◽

Stephen Butt

Keyword(s):

Optimization Technique ◽

Gas Production ◽

Production Optimization ◽

Vertical Wells ◽

Gas Reservoirs ◽

Gas Field ◽

Nodal Analysis ◽

Prospective Application ◽

Overall Performance ◽

Inflow Performance

Abstract The overall performance of gas reservoirs and the optimization of production, as well as its sensitivity analysis, are affected by several factors such as reservoir pressure, well configuration and surface facilities. The Habiganj well no. 06 (HBJ-06) is one of the significant gas-producing vertical wells of the Habiganj gas field, currently producing 14.963 MMscfd of natural gas from the upper gas sand. The widely used Nodal analysis is an optimization technique to improve the performance and was applied for the HBJ-06 to increase its production rate by optimizing manners. By this analysis, each component starting from the reservoir to the outlet pressure of the separator was identified as a resistance in the system by evaluating their inflow performance relationship and vertical lift performance. The F.A.S.T. VirtuWell™ software package was used to perform this analysis, where the declinations of wellhead pressures were suggested as 1300, 1200, 1100 and 1000 psi(a) without any modification of the tubing diameter and skin factor. Hence, the respective optimized rates of the daily gas production were increased to 38.481, 40.993, 43.153 and 46.016 MMscfd. At the same time, the optimized condensate gas ratio was calculated as 0.07, 0.06, 0.06 and 0.05, associated with the optimized condensate water ratio of 0.11, 0.10, 0.09 and 0.08, respectively.

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Short-term steady-state production optimization of offshore oil platforms: wells with dual completion (gas-lift and ESP) and flow assurance

Top ◽

10.1007/s11750-021-00604-2 ◽

2021 ◽

Author(s):

Eduardo Rauh Müller ◽

Eduardo Camponogara ◽

Laio Oriel Seman ◽

Eduardo Otte Hülse ◽

Bruno Ferreira Vieira ◽

...

Keyword(s):

Steady State ◽

Production Optimization ◽

Flow Assurance ◽

Short Term ◽

Oil Platforms ◽

Offshore Oil Platforms ◽

State Production ◽

Offshore Oil ◽

Gas Lift

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An Innovative Well Intervention for Production Optimization in Depleted Gas Reservoirs Thru Coil Tubing

Proc. Indon. Petrol. Assoc., Digital Technical Conference, 2020 ◽

10.29118/ipa20-e-395 ◽

2020 ◽

Author(s):

D. Wijayanto

Keyword(s):

Cost Effective ◽

Production Optimization ◽

Well Test ◽

Gas Reservoirs ◽

Well Productivity ◽

Optimum Result ◽

Coiled Tubing ◽

Well Stimulation ◽

Depleted Gas Reservoirs ◽

Head Pressure

Coil Tubing operated in NL wells, South Sumatera because of depleted reservoir pressure. Objective of coiled tubing operation are sand clean-out and acid stimulation to restore well productivity. Previously in NL wells has used a snubbing unit in intervention well but the results were not good. Formation damage was suspected due to packer fluid introduced into formation during snubbing job. Production optimization in brownfield is required to extend the economic producing life of the field using cost-effective and low-risk technologies. Well stimulation is generally proposed to enhance well productivity by acidizing treatment. Acidizing in sandstone applied in Medco to improve well productivity. But loss problem got in conventional rig operation during killing well in low reservoir gas well. Coiled tubing (CTU) can solve the problem and can operate without killing the well. Recipe acid HCl 15% get optimum in solubility test around 28-31%. Coiled Tubing Operation applied pulsonic method to get optimum result. After CTU Job (clean sand out & acidizing), well productivity improved refer to gas rate and flowing well-head pressure (FWHP) monitoring. Initial gas gain was more than 2.5 MMSCFD from 2 wells (NL-X1 and NL-X2) that were treated with CTU acid stimulation. Gas cumulative is around 176 MMSCF (3 months production) and still counting. Further evaluation will be conducted by performing complete well test (transient analysis). As conclusion, coiled tubing operation has proven to become effective well intervention in depleted gas wells to improve production optimization and open the opportunity to unlock potential in other wells which experiencing similar challenges. This paper shares case study, how to develop acid stimulation strategy covering guideline in acid selection and deploy acid without killing well in South Sumatra.

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Simultaneous Flow Assurance and Production Optimization Using Chemical Paraffin Inhibition Method

10.2118/193515-ms ◽

2018 ◽

Author(s):

Kenechukwu Obiajulu Nwankwo ◽

Chijioke James Chikwekwem ◽

Princess Christiana Nwankwo

Keyword(s):

Production Optimization ◽

Flow Assurance

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Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight- and Shale-Gas Reservoirs: Material Failure and Enhanced Permeability

SPE Journal ◽

10.2118/155640-pa ◽

2014 ◽

Vol 19 (06) ◽

pp. 1110-1125 ◽

Cited By ~ 10

Author(s):

Jihoon Kim ◽

George J. Moridis

Keyword(s):

Shale Gas ◽

Shear Failure ◽

Double Porosity ◽

Gas Production ◽

Coupled Flow ◽

Gas Reservoirs ◽

Shale Gas Reservoirs ◽

Tightly Coupled ◽

Secondary Fractures ◽

Porosity Model

Summary We investigate coupled flow and geomechanics in gas production from extremely low-permeability reservoirs such as tight- and shale-gas reservoirs, using dynamic porosity and permeability during numerical simulation. In particular, we take the intrinsic permeability as a step function of the status of material failure, and the permeability is updated every timestep. We consider gas reservoirs with the vertical and horizontal primary fractures, using the single- and dynamic double-porosity (dual-continuum) models. We modify the multiple-porosity constitutive relations for modeling the double porous continua for flow and geomechanics. The numerical results indicate that the production of gas causes redistribution of the effective-stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs not only near the fracture tips but also away from the primary fractures, which indicates the generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which, in turn, causes a change in the distribution of geomechanical variables. From various numerical tests, we find that shear failure is enhanced by a large pressure drop at the production well, a high Biot's coefficient, and low frictional and dilation angles. Smaller spacing between the horizontal wells also contributes to faster secondary fracturing. When the dynamic double-porosity model is used, we observe a faster evolution of the enhanced-permeability areas than that obtained from the single-porosity model, mainly because of a higher permeability of the fractures in the double-porosity model. These complicated physics for stress-sensitive reservoirs cannot properly be captured by the uncoupled or flow-only simulation, and, thus, tightly coupled flow and geomechanical models are highly recommended to describe accurately the reservoir behavior during gas production in tight- and shale-gas reservoirs and to design production scenarios smartly.

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