Field Studies of Drilling and Completion Fluids to Minimize Damage and Enhance Gas Production in Unconventional Reservoirs

2007 ◽  
Author(s):  
Glenn S. Penny ◽  
John Thomas Pursley
Keyword(s):  
Field Studies ◽  
Gas Production ◽  
Unconventional Reservoirs ◽  
Completion Fluids

Field Case Studies of Completion Fluids to Enhance Oil and Gas Production in Depleted Unconventional Reservoirs

2007 ◽  
Author(s):  
John Thomas Pursley ◽  
Glenn S. Penny ◽  
John H. Benton ◽  
David Terrell Greene ◽  
Gary Scott Nordlander ◽  
...  
Keyword(s):  
Case Studies ◽  
Oil And Gas ◽  
Gas Production ◽  
Unconventional Reservoirs ◽  
Oil And Gas Production ◽  
Field Case ◽  
Completion Fluids

A New Alginate-Based Rapid Method for Determining Coliforms in Milk

2003 ◽  
Vol 66 (11) ◽  
pp. 2146-2150 ◽  
Author(s):  
SU-SEN CHANG ◽  
PETER M. GRAY ◽  
GUN-JO WOO ◽  
DONG-HYUN KANG
Keyword(s):  
Rapid Method ◽  
Color Change ◽  
Enterobacter Cloacae ◽  
Raw Milk ◽  
Field Studies ◽  
Gas Production ◽  
Detection Time ◽  
Total Coliforms ◽  
Plating Method ◽  
Peptone Water

A new rapid method for monitoring coliforms was developed on the basis of the instant gelling effects of alginate and calcium. The effectiveness of this new method in the detection of coliforms was evaluated. Tests involving Escherichia coli, Enterobacter cloacae, Klebsiella pneumoniae, total coliforms in milk, cold-injured coliforms, and total coliforms in raw milk were carried out. The bacterial samples were diluted in 0.2% peptone water containing 90 mM CaCl2 and added into test tubes containing modified purple broth base medium. Coliform concentrations were determined on the basis of the time of color change and gas production in the alginate tubes. All results obtained by the alginate method correlated strongly with those obtained by the conventional violet red bile agar (VRBA) plating method. The alginate method reduced detection time by 12 to 14 h compared with the conventional VRBA plating method. The alginate method can be applied in field studies more easily than melted-agar systems can. The results of this study indicate that the alginate method is an accurate, rapid, simple, and economical way to monitor and estimate concentrations of total coliforms in food.

scholarly journals Natural Gas Production from Methane Hydrate Deposits Using Clathrate Sequestration: State-of-the-Art Review and New Technical Approaches

2011 ◽  
Vol 2011 ◽  
pp. 1-6 ◽  
Author(s):  
Annick Nago ◽  
Antonio Nieto
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Carbon Dioxide Emissions ◽  
Methane Hydrate ◽  
Field Studies ◽  
Gas Production ◽  
Methane Hydrates ◽  
Methane Recovery ◽  
Natural Gas Production ◽  
Recovery Potential

This paper focuses on reviewing the currently available solutions for natural gas production from methane hydrate deposits using CO2 sequestration. Methane hydrates are ice-like materials, which form at low temperature and high pressure and are located in permafrost areas and oceanic environments. They represent a huge hydrocarbon resource, which could supply the entire world for centuries. Fossil-fuel-based energy is still a major source of carbon dioxide emissions which contribute greatly to the issue of global warming and climate change. Geological sequestration of carbon dioxide appears as the safest and most stable way to reduce such emissions for it involves the trapping of CO2 into hydrocarbon reservoirs and aquifers. Indeed, CO2 can also be sequestered as hydrates while helping dissociate the in situ methane hydrates. The studies presented here investigate the molecular exchange between CO2 and CH4 that occurs when methane hydrates are exposed to CO2, thus generating the release of natural gas and the trapping of carbon dioxide as gas clathrate. These projects include laboratory studies on the synthesis, thermodynamics, phase equilibrium, kinetics, cage occupancy, and the methane recovery potential of the mixed CO2–CH4 hydrate. An experimental and numerical evaluation of the effect of porous media on the gas exchange is described. Finally, a few field studies on the potential of this new gas hydrate recovery technique are presented.

Multiphase gas compression to boost unconventional production and reserves

2019 ◽  
Vol 59 (1) ◽  
pp. 268
Author(s):  
Robert Perry ◽  
Jeffrey Martini ◽  
Pandurang Kulkarni
Keyword(s):  
Atmospheric Pressure ◽  
Gas Production ◽  
Unconventional Reservoirs ◽  
Operational Flexibility ◽  
Flow Conditions ◽  
Artificial Lift ◽  
Gas Compression ◽  
Order Of Magnitude ◽  
Inflow Performance ◽  
Gas Lift

Hydraulic fracturing has significantly increased well inflow performance in unconventional reservoirs, enabling their economic development. This improved inflow performance has opened up the possibility of leveraging further reserves and production gains through artificial lift or similar production enhancement techniques. A ‘multiphase compressor’ has been developed with differentiating characteristics:compression ratios of up to 40:1 (an order of magnitude greater than conventional compressors), ability to handle a broad range of multiphase conditions, and significant operational flexibility. This makes it very well suited for deployment in unconventional reservoirs at the wellhead, either on its own in a multiphase boosting capacity or in conjunction with other forms of artificial lift (such as gas lift, plunger lift, and potentially downhole pumping). The multiphase compressor has been deployed in the field on naturally flowing wells, and wells with plunger lift. Production rate increases of up to 300% were achieved, and production was maintained in wells that would have otherwise loaded up and died. Wells were unloaded by reducing wellhead flowing pressures to atmospheric pressure at the compressor suction – similar to flowing the well into an ‘open topped’ tank. The multiphase compressor demonstrated a very broad operating range and the ability to handle slug flow conditions. Further applications to be tested include gas lift and downhole pumping in shale wells, gas wells that have received fracture hits and require clean up from invaded fracture fluids, and coal seam gas production. Multiphase compression has significant potential to increase both production and reserves from unconventional reservoirs and wells.

Field Study of Completion Fluids To Enhance Gas Production in the Barnett Shale

2006 ◽  
Author(s):  
Glenn S. Penny ◽  
Terrell Allen Dobkins ◽  
John Thomas Pursley
Keyword(s):  
Field Study ◽  
Gas Production ◽  
Barnett Shale ◽  
Completion Fluids

Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

2016 ◽  
Vol 56 (1) ◽  
pp. 415 ◽  
Author(s):  
Yang Fei ◽  
Mary Gonzalez Perdomo ◽  
Viet Quoc Nguyen ◽  
Zhongyu Lei ◽  
Kunakorn Pokalai ◽  
...  
Keyword(s):  
Multiphase Flow ◽  
South Australia ◽  
Fracture Propagation ◽  
Flow Simulation ◽  
Gas Production ◽  
Propagation Model ◽  
Unconventional Reservoirs ◽  
Fracturing Fluids ◽  
Water Based ◽  
Cooper Basin

In many unconventional reservoirs, gas wells do not perform to their potential when water-based fracturing fluids are used for treatments. The sub-optimal fracture productivity can be attributed to many factors such as effective fracture length loss, low load fluid recovery, flowback time, and water availability. The development of unconventional reservoirs has, therefore, prompted the industry to reconsider waterless fracturing treatments as viable alternatives to water-based fracturing fluids. In this paper, a simulation approach was used by coupling a fracture propagation model with a multiphase flow model. The Toolachee Formation is a tight sand in the Cooper Basin, around 7,200 ft in depth, and has been targeted for gas production. In this study, a 3D hydraulic fracture propagation model was first developed to provide fracture dimensions and conductivity. Then, from an offset well injection fall off test, the model was tuned by using different calibration parameters such as fracture gradient and closure pressure to validate the model. Finally, fracture propagation model outputs were used as the inputs for multiphase flow reservoir simulation. A large number of cases were simulated based on different fraccing fluids and the concept of permeability jail to represent several water-induced damage effects. It was found that LPG was a successful treatment, especially in a reservoir where the authors suspected the presence of permeability jails. The authors also observed that total flowback recovery approached 76% within 60 days in the case of using gelled LPG. Modelling predictions also support the need for high-quality foam, and LPG can be expected to bring long-term productivity gains in normal tight gas relative permeability behaviour.

A Generalized Framework Model for the Simulation of Gas Production in Unconventional Gas Reservoirs

SPE Journal ◽  
2014 ◽  
Vol 19 (05) ◽  
pp. 845-857 ◽  
Author(s):  
Yu-Shu Wu ◽  
Jianfang Li ◽  
Didier-Yu Ding ◽  
Cong Wang ◽  
Yuan Di
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Gas Production ◽  
Unconventional Reservoirs ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Unconventional Gas ◽  
Shale Gas Reservoirs ◽  
Framework Model ◽  
Unconventional Gas Reservoirs

Summary Unconventional gas resources from tight-sand and shale gas reservoirs have received great attention in the past decade around the world because of their large reserves and technical advances in developing these resources. As a result of improved horizontal-drilling and hydraulic-fracturing technologies, progress is being made toward commercial gas production from such reservoirs, as demonstrated in the US. However, understandings and technologies needed for the effective development of unconventional reservoirs are far behind the industry needs (e.g., gas-recovery rates from those unconventional resources remain very low). There are some efforts in the literature on how to model gas flow in shale gas reservoirs by use of various approaches—from modified commercial simulators to simplified analytical solutions—leading to limited success. Compared with conventional reservoirs, gas flow in ultralow-permeability unconventional reservoirs is subject to more nonlinear, coupled processes, including nonlinear adsorption/desorption, non-Darcy flow (at both high flow rate and low flow rate), strong rock/fluid interaction, and rock deformation within nanopores or microfractures, coexisting with complex flow geometry and multiscaled heterogeneity. Therefore, quantifying flow in unconventional gas reservoirs has been a significant challenge, and the traditional representative-elementary-volume- (REV) based Darcy's law, for example, may not be generally applicable. In this paper, we discuss a generalized mathematical framework model and numerical approach for unconventional-gas-reservoir simulation. We present a unified framework model able to incorporate known mechanisms and processes for two-phase gas flow and transport in shale gas or tight gas formations. The model and numerical scheme are based on generalized flow models with unstructured grids. We discuss the numerical implementation of the mathematical model and show results of our model-verification effort. Specifically, we discuss a multidomain, multicontinuum concept for handling multiscaled heterogeneity and fractures [i.e., the use of hybrid modeling approaches to describe different types and scales of fractures or heterogeneous pores—from the explicit modeling of hydraulic fractures and the fracture network in stimulated reservoir volume (SRV) to distributed natural fractures, microfractures, and tight matrix]. We demonstrate model application to quantify hydraulic fractures and transient flow behavior in shale gas reservoirs.

scholarly journals Shale Poroelastic Effects on Well Performance Analysis of Shale Gas Reservoirs

Fuels ◽  
2021 ◽  
Vol 2 (2) ◽  
pp. 130-143
Author(s):  
Ebrahim Fathi ◽  
Fatemeh Belyadi ◽  
Bahiya Jabbar
Keyword(s):  
History Matching ◽  
Gas Transport ◽  
Gas Production ◽  
Unconventional Reservoirs ◽  
Sorption Behavior ◽  
Governing Equations ◽  
Hydrocarbon Production ◽  
Multi Scale ◽  
Pore Compressibility ◽  
And Storage

The effect of poroelastic properties of the shale matrix on gas storage and transport mechanisms has gained significant attention, especially during history-matching and hydrocarbon production forecasting in unconventional reservoirs. The common oil and gas industry practice in unconventional reservoir simulation is the extension of conventional reservoir simulation that ignores the dynamic behavior of matrix porosity and permeability as a function of reservoir effective net stress. This approach ignores the significant impact of the poroelastic characteristics of the shale matrix on hydrocarbon production. The poroelastic characteristics of the shale matrix highly relate to the shale matrix geomechanical properties, such as the Young’s Modulus, Poisson’s ratio, bulk modulus, sorption behavior, total organic content (TOC), mineralogy and presence of natural fractures in the multi-scale shale structure. In this study, in order to quantify the effect of the poroelasticity of the shale matrix on gas production, a multi-continuum approach was employed in which the shale matrix was divided into organic materials, inorganic materials and natural fractures. The governing equations for gas transport and storage in shale were developed from the basic fundamentals of mass and momentum conservation equations. In this case, gas transport in organics was assumed to be diffusive, while gas transport in inorganics was governed by convection. Finally, a fracture system was added to the multi-scale shale gas matrix, and the poroelastic effect of the shale matrix on transport and storage was investigated. A modified Palmer and Mansoori model (1998) was used to include the pore compression, matrix swelling/shrinkage and desorption-induced deformation of shale organic matter on the overall pore compressibility of the shale matrix. For the inorganic part of the matrix, relations between rock mechanical properties and the pore compressibility were obtained. A dual Langmuir–Henry isotherm was also used to describe the sorption behavior of shale organic materials. The coupled governing equations of gas storage and transport in the shale matrix were then solved using the implicit finite difference approach using MATLAB. For this purpose, rock and fluid properties were obtained using actual well logging and core analysis of the Marcellus gas well. The results showed the importance of the poroelastic effect on the pressure response and rate of gas recovery from the shale matrix. The effect was found to be mainly due to desorption-induced matrix deformation at an early stage. Coupling the shale matrix gas production including the poroelastic effect in history-matching the gas production from unconventional reservoirs will significantly improve engineering completion design optimization of the unconventional reservoirs by providing more accurate and robust production forecasts for each hydraulic fracture stage.

Nitrile Rubber—Past, Present and Future

1995 ◽  
Vol 68 (3) ◽  
pp. 540-546 ◽  
Author(s):  
D. L. Hertz ◽  
Hermann Bussem ◽  
T. W. Ray
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Nitrile Rubber ◽  
Aqueous Environment ◽  
Paper Briefly ◽  
Oil And Gas Production ◽  
The Past ◽  
Well Stimulation ◽  
Higher Temperature ◽  
Completion Fluids

Abstract Nitrile rubber (NBR) has been the work-horse elastomer in oil and gas production for the past fifty years. Random seal and packer failures have been encountered in the more agressive fields. The higher temperatures and increasing percentages of hydrogen sulfide (H2S), naturally occuring or through well stimulation directly or indirectly, initiate the failure mechanism(s). Future applications of nitrile rubber in higher temperature production should only be considered after reviewing the range of potential chemical attacks that are possible by of the aqueous environment (well fluids, completion fluids and stimulation fluids). This paper briefly outlines the scope of chemical attacks that can and will be encountered.

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