This document discusses flow assurance challenges for developing the remote Shtokman gas field in the Arctic and outlines strategies to manage the risks. It describes the field and harsh environment, outlines the development plan including offshore and onshore facilities, and identifies key flow assurance risks like hydrate formation, corrosion, and liquid accumulation. It then details strategies to manage these risks through chemical injection, pipeline design and insulation, fluid processing, and operating procedures. The development aims to safely produce gas from this remote Arctic field.
The document discusses new technologies applied to develop tight hydrocarbon reservoirs in the Cambay Basin of India. Specifically, it details the application of horizontal drilling, multistage fracturing, and microseismic monitoring in a well in the Cambay Field. This well is expected to produce 300,000-500,000 m3/d of gas, compared to typical production of 30,000-50,000 m3/d from vertical wells. These new technologies could also be applied in other Indian basins containing tight reservoirs to help meet the country's growing energy demand.
This document discusses challenges and solutions related to deep water drilling. It describes different types of rigs used for deep water drilling at various water depths. Key challenges discussed include gas hydrates, reactive formations, low fracture gradients, large mud volumes, low flow line temperatures, and high rig costs. Solutions provided relate to additive selection, temperature and pressure management, casing design, logistics planning, and optimization to reduce costs and time.
This document discusses tight reservoirs, which are reservoirs with very low permeability (less than 0.1 mD) and porosity (less than 10%). It defines tight gas reservoirs, tight oil reservoirs, and the characteristic properties of tight reservoirs, such as low porosity and permeability. It also discusses the importance of logging, factors to consider for tight reservoirs like geologic and reservoir properties, and techniques used to produce from tight reservoirs, including hydraulic fracturing and horizontal drilling. Tight reservoirs account for a large portion of remaining oil and gas reserves and require advanced drilling and completion techniques to produce economically.
SPE 165151 The Long-Term Production Performance of Deep HPHT Gas Condensate ...jdowns
Maps and analyses the long-term production of eight HPHT gas and condensate fields in which formate brines were the last well construction fluids to contact the producing reservoirs
The document discusses reservoir simulation of coal bed methane (CBM). It begins with an introduction to CBM, explaining how gas is stored in coal seams and produced through desorption, diffusion through micropores, and flow through fractures. The document then discusses reservoir simulation software Comet3, which uses dual-porosity modeling to simulate gas and water production from CBM reservoirs. The author conducted a simulation of a single well producing from 5 coal seams, presenting input parameters, results graphs of gas and water production rates over time, and conclusions on well spacing effects.
This document discusses the benefits of using cross-linked polymers in high-pressure, high-temperature connections. It explains that first-generation polymers have limitations in extreme conditions but that next-generation polymers are engineered for specific HPHT applications up to 600 degrees Fahrenheit and 15,000 PSI. Recent testing showed a next-generation polymer-sealed connection held at over 15,000 PSI, while a first-generation compound failed at 11,500 PSI. The conclusion is that advanced polymers enhance performance in premium connections and can be customized for challenging HPHT environments.
High Temperature High Pressure (HTHP) reservoirs have depths greater than 15,000 feet, pressures over 15,000 psi, and temperatures from 325-500°F. Several considerations are important for cementing in these conditions, including accurate temperature measurement, sufficient slurry density and viscosity, retardation, strength stability additives, filtration control, and preventing gas migration along the cement sheath. Specialty cements and additives can help address gas flow potential from minor to severe levels.
This document discusses unconventional reservoirs and shale gas. It begins with defining unconventional resources as hydrocarbon reservoirs with low permeability and porosity that are difficult to produce. Shale gas is then introduced as natural gas trapped in shale formations. The document outlines a roadmap for identifying and developing shale plays, including geological, geophysical, geochemical, and geomechanical approaches. Key factors like total organic carbon content, thermal maturity, and brittleness are examined. The concept of a "sweet spot" is introduced as the most prospective volumes within a shale play, characterized by properties like thickness and permeability. The document concludes with thanking the audience.
The document discusses new technologies applied to develop tight hydrocarbon reservoirs in the Cambay Basin of India. Specifically, it details the application of horizontal drilling, multistage fracturing, and microseismic monitoring in a well in the Cambay Field. This well is expected to produce 300,000-500,000 m3/d of gas, compared to typical production of 30,000-50,000 m3/d from vertical wells. These new technologies could also be applied in other Indian basins containing tight reservoirs to help meet the country's growing energy demand.
This document discusses challenges and solutions related to deep water drilling. It describes different types of rigs used for deep water drilling at various water depths. Key challenges discussed include gas hydrates, reactive formations, low fracture gradients, large mud volumes, low flow line temperatures, and high rig costs. Solutions provided relate to additive selection, temperature and pressure management, casing design, logistics planning, and optimization to reduce costs and time.
This document discusses tight reservoirs, which are reservoirs with very low permeability (less than 0.1 mD) and porosity (less than 10%). It defines tight gas reservoirs, tight oil reservoirs, and the characteristic properties of tight reservoirs, such as low porosity and permeability. It also discusses the importance of logging, factors to consider for tight reservoirs like geologic and reservoir properties, and techniques used to produce from tight reservoirs, including hydraulic fracturing and horizontal drilling. Tight reservoirs account for a large portion of remaining oil and gas reserves and require advanced drilling and completion techniques to produce economically.
SPE 165151 The Long-Term Production Performance of Deep HPHT Gas Condensate ...jdowns
Maps and analyses the long-term production of eight HPHT gas and condensate fields in which formate brines were the last well construction fluids to contact the producing reservoirs
The document discusses reservoir simulation of coal bed methane (CBM). It begins with an introduction to CBM, explaining how gas is stored in coal seams and produced through desorption, diffusion through micropores, and flow through fractures. The document then discusses reservoir simulation software Comet3, which uses dual-porosity modeling to simulate gas and water production from CBM reservoirs. The author conducted a simulation of a single well producing from 5 coal seams, presenting input parameters, results graphs of gas and water production rates over time, and conclusions on well spacing effects.
This document discusses the benefits of using cross-linked polymers in high-pressure, high-temperature connections. It explains that first-generation polymers have limitations in extreme conditions but that next-generation polymers are engineered for specific HPHT applications up to 600 degrees Fahrenheit and 15,000 PSI. Recent testing showed a next-generation polymer-sealed connection held at over 15,000 PSI, while a first-generation compound failed at 11,500 PSI. The conclusion is that advanced polymers enhance performance in premium connections and can be customized for challenging HPHT environments.
High Temperature High Pressure (HTHP) reservoirs have depths greater than 15,000 feet, pressures over 15,000 psi, and temperatures from 325-500°F. Several considerations are important for cementing in these conditions, including accurate temperature measurement, sufficient slurry density and viscosity, retardation, strength stability additives, filtration control, and preventing gas migration along the cement sheath. Specialty cements and additives can help address gas flow potential from minor to severe levels.
This document discusses unconventional reservoirs and shale gas. It begins with defining unconventional resources as hydrocarbon reservoirs with low permeability and porosity that are difficult to produce. Shale gas is then introduced as natural gas trapped in shale formations. The document outlines a roadmap for identifying and developing shale plays, including geological, geophysical, geochemical, and geomechanical approaches. Key factors like total organic carbon content, thermal maturity, and brittleness are examined. The concept of a "sweet spot" is introduced as the most prospective volumes within a shale play, characterized by properties like thickness and permeability. The document concludes with thanking the audience.
The document summarizes the pre-commissioning of the Nord Stream natural gas pipelines, which transport natural gas from Russia to Germany. Some key points:
- Nord Stream consists of two 1,224 km pipelines running along the Baltic Sea floor, the longest single-section offshore pipelines ever built.
- Pre-commissioning included flooding the pipelines with water, cleaning and gauging them using pigs, then pressure testing and dewatering prior to gas commissioning.
- Effective planning was required to coordinate the complex offshore and onshore pre-commissioning activities given constraints like winter freezing of the Baltic Sea.
- Offshore operations used a vessel-based spread for flooding, cleaning and gauging. On
The document discusses various methods for controlling water production in oil wells. It begins by explaining the reasons water control is important and outlines different water types. It then describes potential mechanical, physical, and chemical solutions for shutting off water sources. These include tools like packers and bridge plugs, materials like cement and sand plugs, and chemicals like polymer gels and resins. The document emphasizes the importance of proper well diagnostics to identify the specific water problem before selecting the most appropriate water control solution.
Exploring Tight Gas Reservoir Using Intelligent Well TechnologyAbhinav Bisht
The document discusses exploring tight gas reservoirs economically using intelligent well completion (IWC) technology. Tight gas is found in low permeability rock and requires hydraulic fracturing and directional drilling to produce. IWC uses remotely operated valves for selective multi-stage fracturing of horizontal wells to improve efficiency. A case study describes how IWC and microseismic monitoring in China's Changbei Field helped optimize subsequent horizontal well completions in that field.
The document summarizes the methods used to characterize a shale reservoir and determine its original gas in place (OGIP) and CO2 storage capacity. Key steps included discretizing structure maps, uploading data to Matlab for surface maps, digitizing well logs, calculating petrophysical properties, and using Langmuir isotherm coefficients to estimate OGIP and storage capacity. Total OGIP was estimated at 14.12 trillion standard cubic feet with the highest values in the bottom center. Total CO2 storage capacity was 14.58 trillion standard cubic feet, also highest in the bottom center. Monte Carlo analysis was used to account for uncertainties.
Reservoir development plans require dynamic strategies to optimize production. Recovery methods can be initiated at any stage to improve efficiency. It is common for development plans to change over time due to new understanding, performance, constraints, economics or technologies. Screening studies for improved or enhanced oil recovery methods should consider technical feasibility as well as availability of resources and include decision analysis to define robust project options early. Preliminary performance predictions using simple models can help evaluate recovery process potential in a reservoir.
The document summarizes the Hodhod Field Development Project in the State of Pennaga. Key points include:
- The Hodhod offshore oil field was discovered and contains over 3 billion stock tank barrels of oil initially in place.
- Several development scenarios were evaluated including vertical wells, horizontal wells, waterflooding, surfactant flooding, and water alternating gas injection to optimize recovery.
- The preferred development plan involves using horizontal production wells, waterflooding, and later water alternating gas injection which is estimated to recover over 28% of the oil initially in place.
Paper Aachen- Najder engineering 2008.04.17Tomasz Najder
This document summarizes rock grouting projects in Iceland that involved tunneling through complicated geological conditions. It describes an emergency rock grouting project to seal tunnels in Isafjordur that encountered major faults with water inflows over 1,000 liters/second. Improvements were made to grouting procedures including using quick-setting cement grouts and polyurethane resins to stabilize the rock and reduce water inflows. It also discusses a project in Botnsheiði Tunnel that intersected a fault with up to 1 cubic meter/second of water. Grouting methods were optimized using accelerated cement mixes, lightweight sand, and polyurethane resins to stabilize the rock and seal cracks in extreme cold and
nFluids Nanoparticle Technology Additives for Drilling Fluids & Oil & Gas Ap...Dr. Jeff Forsyth
An innovative Canadian technology company is commercializing a nanoparticle technology platform to develop drilling fluid additives. Laboratory tests show the company's first product, nForcer, can reduce drilling fluid losses by up to 90%, increase wellbore fracture pressure resistance by up to 60%, and reduce friction by up to 50%. Field tests in Alberta demonstrated up to 30% reduction in mud volume losses. The nanoparticles form stronger, thinner filter cakes and seals in fractures and pores to strengthen the wellbore.
This document summarizes research on developing stable and degradable fracturing fluids using oilfield produced formation water. The fluids were formulated with guar polymers and crosslinked using borates or zirconates. Rheology tests measured viscosity at temperatures from 210-260°F, and residue analysis tested degradation with breakers at 185°F. Results showed the fluids provided sufficient viscosity for transporting proppants into fractures, and could be degraded to low viscosity to enhance hydrocarbon recovery. Using produced water reduced operating costs and environmental impacts compared to fresh water.
The document discusses research on the distribution of oil and water in the eastern block of the Chao202-2 area in China. It establishes standards for identifying oil, poor oil, dry, and water layers using well logging data. Analysis shows structural reservoirs are dominant and fault and sand body configuration control oil-water distribution. Oil-water distribution varies between fault blocks from "up oil, bottom water" to "up water, bottom oil" depending on structure and sand body development.
First use of cesium formate LSOBM as well perforating fluid (2002) John Downs
This document discusses the development and application of a low-solid oil-based perforation fluid to maximize well productivity in the Visund oil field. Laboratory tests showed that conventional calcium bromide brines can impair permeability and react with zinc perforation charges. A new low-solid invert emulsion perforation fluid with cesium formate was developed and successfully used to perforate well A-23H, resulting in productivity 3-4 times higher than previous wells in the field.
Mud logging involves collecting and analyzing drill cuttings and mud properties to interpret lithology and detect hydrocarbon shows. It relies on mud circulation from the mud pump through the drill string and annulus to the shale shaker where cuttings are examined. The mud logger monitors and records drilling parameters and cuttings data to help assess the producibility of formations. However, mud logging becomes less accurate at depths over 3000m where cuttings are mixed and it takes longer for mud to return to the surface.
The document summarizes a simulation study on the effects of well spacing, permeability anisotropy, and the Palmer and Mansoori model on coalbed methane production. The study used a dual-porosity simulation model to analyze gas production from a single coal seam under different well spacing and configurations. It found that closer well spacing increased production rates and recovery. Placing wells along the direction of higher permeability in anisotropic reservoirs also improved recovery. The Palmer and Mansoori model, which accounts for matrix shrinkage and cleat compression, impacted predicted production rates and should be considered in coalbed methane simulations.
Review of EOR Selection for light tight oil
Key Themes:
Upfront EOR Development Planning
Cash is king but Permeability Rules
Geology Selects Technology
Nanospheres, Steam Flooding, Misc Gas Flooding, EOR Selection Criteria
Coal bed methane is a process that extracts natural gas from coal seams without mining the coal. Water is pumped into the underground coal seams to create fractures that allow the trapped methane gas to flow into wells drilled into the seams. The water and gas are then separately pumped up through the wells. While coal bed methane production avoids some mining costs and risks, it can negatively impact local groundwater and cause air pollution if not properly managed through water disposal and casing/cementing of wells.
This document discusses various water and gas conformance technologies used to improve sweep efficiency in oil reservoirs. It begins with an overview of water conformance methods like injection profile modification and BrightWater technology, providing a field case example from Alaska where BrightWater increased incremental oil production. It also summarizes gas conformance technologies, noting foams are commonly used to modify gas injection profiles or shut off high GOR wells. The document concludes with descriptions of polymer flooding, ZL Nano-spheres, and the status of foam applications in North Sea reservoirs.
Ports-to-Plains Energy Summit
Omni Interlocken Resort
Broomfield, CO
April 7, 2011
Hydraulic fracturing has been in the news lately. Learn exactly what the process is and how it is impacting economic growth and energy security.
Coal bed methane (CBM) is methane found stored in coal seams. There are two main methods to estimate the amount of CBM in a region: drilling cores to measure gas content or performing calculations based on known coal characteristics. While CBM development provides benefits, the associated produced water poses challenges as it is often saline and sodic. Current management practices for CBM water include discharge to streams, land application, and impounding, but all methods risk subsurface impacts due to water quality issues. Proper management is needed to safely use CBM water for irrigation or disposal.
The document discusses the preparation of boiler feed water (BFW) from raw water. Raw water is processed through demineralization to remove minerals, producing demineralized (DM) water. DM water is further conditioned in a deaerator, where it is mixed with recycled condensate, heated with low pressure steam to remove dissolved gases, and oxygen scavengers like hydrazine are added to produce high quality BFW for use in boilers. Maintaining proper BFW quality through continuous and intermittent blowdown is important to minimize impurities in the boiler system and produce stable steam.
This document discusses challenges with cementing in deepwater environments, including shallow water flows and gas hydrate destabilization due to cement heat of hydration. It presents a solution of optimizing cement slurry design to reduce heat of hydration through lowering the calcium silicate reaction enthalpies. Experimental data shows that a cement system designed with a lower heat of hydration reduces temperature rise and develops strength rapidly enough to prevent issues. This optimized system was successfully implemented in the field to help prevent gas hydrate destabilization during cementing.
Key aspects of reservoir evaluation for deep water reservoirsM.T.H Group
The document summarizes key aspects of reservoir evaluation for deep water projects. It discusses challenges including geomechanics, reservoir characterization of thin beds and compartmentalization, and flow assurance requiring accurate fluid characterization. Reservoir characterization is identified as the biggest risk due to complex lithology, thin beds, and low contrast pay. Accurate fluid analysis and asphaltene characterization can help determine reservoir connectivity. Operator priorities include minimizing operational risk through rig efficiency and completion/production reliability. Reservoir evaluation is critical for deep water projects due to significant costs.
The document summarizes the pre-commissioning of the Nord Stream natural gas pipelines, which transport natural gas from Russia to Germany. Some key points:
- Nord Stream consists of two 1,224 km pipelines running along the Baltic Sea floor, the longest single-section offshore pipelines ever built.
- Pre-commissioning included flooding the pipelines with water, cleaning and gauging them using pigs, then pressure testing and dewatering prior to gas commissioning.
- Effective planning was required to coordinate the complex offshore and onshore pre-commissioning activities given constraints like winter freezing of the Baltic Sea.
- Offshore operations used a vessel-based spread for flooding, cleaning and gauging. On
The document discusses various methods for controlling water production in oil wells. It begins by explaining the reasons water control is important and outlines different water types. It then describes potential mechanical, physical, and chemical solutions for shutting off water sources. These include tools like packers and bridge plugs, materials like cement and sand plugs, and chemicals like polymer gels and resins. The document emphasizes the importance of proper well diagnostics to identify the specific water problem before selecting the most appropriate water control solution.
Exploring Tight Gas Reservoir Using Intelligent Well TechnologyAbhinav Bisht
The document discusses exploring tight gas reservoirs economically using intelligent well completion (IWC) technology. Tight gas is found in low permeability rock and requires hydraulic fracturing and directional drilling to produce. IWC uses remotely operated valves for selective multi-stage fracturing of horizontal wells to improve efficiency. A case study describes how IWC and microseismic monitoring in China's Changbei Field helped optimize subsequent horizontal well completions in that field.
The document summarizes the methods used to characterize a shale reservoir and determine its original gas in place (OGIP) and CO2 storage capacity. Key steps included discretizing structure maps, uploading data to Matlab for surface maps, digitizing well logs, calculating petrophysical properties, and using Langmuir isotherm coefficients to estimate OGIP and storage capacity. Total OGIP was estimated at 14.12 trillion standard cubic feet with the highest values in the bottom center. Total CO2 storage capacity was 14.58 trillion standard cubic feet, also highest in the bottom center. Monte Carlo analysis was used to account for uncertainties.
Reservoir development plans require dynamic strategies to optimize production. Recovery methods can be initiated at any stage to improve efficiency. It is common for development plans to change over time due to new understanding, performance, constraints, economics or technologies. Screening studies for improved or enhanced oil recovery methods should consider technical feasibility as well as availability of resources and include decision analysis to define robust project options early. Preliminary performance predictions using simple models can help evaluate recovery process potential in a reservoir.
The document summarizes the Hodhod Field Development Project in the State of Pennaga. Key points include:
- The Hodhod offshore oil field was discovered and contains over 3 billion stock tank barrels of oil initially in place.
- Several development scenarios were evaluated including vertical wells, horizontal wells, waterflooding, surfactant flooding, and water alternating gas injection to optimize recovery.
- The preferred development plan involves using horizontal production wells, waterflooding, and later water alternating gas injection which is estimated to recover over 28% of the oil initially in place.
Paper Aachen- Najder engineering 2008.04.17Tomasz Najder
This document summarizes rock grouting projects in Iceland that involved tunneling through complicated geological conditions. It describes an emergency rock grouting project to seal tunnels in Isafjordur that encountered major faults with water inflows over 1,000 liters/second. Improvements were made to grouting procedures including using quick-setting cement grouts and polyurethane resins to stabilize the rock and reduce water inflows. It also discusses a project in Botnsheiði Tunnel that intersected a fault with up to 1 cubic meter/second of water. Grouting methods were optimized using accelerated cement mixes, lightweight sand, and polyurethane resins to stabilize the rock and seal cracks in extreme cold and
nFluids Nanoparticle Technology Additives for Drilling Fluids & Oil & Gas Ap...Dr. Jeff Forsyth
An innovative Canadian technology company is commercializing a nanoparticle technology platform to develop drilling fluid additives. Laboratory tests show the company's first product, nForcer, can reduce drilling fluid losses by up to 90%, increase wellbore fracture pressure resistance by up to 60%, and reduce friction by up to 50%. Field tests in Alberta demonstrated up to 30% reduction in mud volume losses. The nanoparticles form stronger, thinner filter cakes and seals in fractures and pores to strengthen the wellbore.
This document summarizes research on developing stable and degradable fracturing fluids using oilfield produced formation water. The fluids were formulated with guar polymers and crosslinked using borates or zirconates. Rheology tests measured viscosity at temperatures from 210-260°F, and residue analysis tested degradation with breakers at 185°F. Results showed the fluids provided sufficient viscosity for transporting proppants into fractures, and could be degraded to low viscosity to enhance hydrocarbon recovery. Using produced water reduced operating costs and environmental impacts compared to fresh water.
The document discusses research on the distribution of oil and water in the eastern block of the Chao202-2 area in China. It establishes standards for identifying oil, poor oil, dry, and water layers using well logging data. Analysis shows structural reservoirs are dominant and fault and sand body configuration control oil-water distribution. Oil-water distribution varies between fault blocks from "up oil, bottom water" to "up water, bottom oil" depending on structure and sand body development.
First use of cesium formate LSOBM as well perforating fluid (2002) John Downs
This document discusses the development and application of a low-solid oil-based perforation fluid to maximize well productivity in the Visund oil field. Laboratory tests showed that conventional calcium bromide brines can impair permeability and react with zinc perforation charges. A new low-solid invert emulsion perforation fluid with cesium formate was developed and successfully used to perforate well A-23H, resulting in productivity 3-4 times higher than previous wells in the field.
Mud logging involves collecting and analyzing drill cuttings and mud properties to interpret lithology and detect hydrocarbon shows. It relies on mud circulation from the mud pump through the drill string and annulus to the shale shaker where cuttings are examined. The mud logger monitors and records drilling parameters and cuttings data to help assess the producibility of formations. However, mud logging becomes less accurate at depths over 3000m where cuttings are mixed and it takes longer for mud to return to the surface.
The document summarizes a simulation study on the effects of well spacing, permeability anisotropy, and the Palmer and Mansoori model on coalbed methane production. The study used a dual-porosity simulation model to analyze gas production from a single coal seam under different well spacing and configurations. It found that closer well spacing increased production rates and recovery. Placing wells along the direction of higher permeability in anisotropic reservoirs also improved recovery. The Palmer and Mansoori model, which accounts for matrix shrinkage and cleat compression, impacted predicted production rates and should be considered in coalbed methane simulations.
Review of EOR Selection for light tight oil
Key Themes:
Upfront EOR Development Planning
Cash is king but Permeability Rules
Geology Selects Technology
Nanospheres, Steam Flooding, Misc Gas Flooding, EOR Selection Criteria
Coal bed methane is a process that extracts natural gas from coal seams without mining the coal. Water is pumped into the underground coal seams to create fractures that allow the trapped methane gas to flow into wells drilled into the seams. The water and gas are then separately pumped up through the wells. While coal bed methane production avoids some mining costs and risks, it can negatively impact local groundwater and cause air pollution if not properly managed through water disposal and casing/cementing of wells.
This document discusses various water and gas conformance technologies used to improve sweep efficiency in oil reservoirs. It begins with an overview of water conformance methods like injection profile modification and BrightWater technology, providing a field case example from Alaska where BrightWater increased incremental oil production. It also summarizes gas conformance technologies, noting foams are commonly used to modify gas injection profiles or shut off high GOR wells. The document concludes with descriptions of polymer flooding, ZL Nano-spheres, and the status of foam applications in North Sea reservoirs.
Ports-to-Plains Energy Summit
Omni Interlocken Resort
Broomfield, CO
April 7, 2011
Hydraulic fracturing has been in the news lately. Learn exactly what the process is and how it is impacting economic growth and energy security.
Coal bed methane (CBM) is methane found stored in coal seams. There are two main methods to estimate the amount of CBM in a region: drilling cores to measure gas content or performing calculations based on known coal characteristics. While CBM development provides benefits, the associated produced water poses challenges as it is often saline and sodic. Current management practices for CBM water include discharge to streams, land application, and impounding, but all methods risk subsurface impacts due to water quality issues. Proper management is needed to safely use CBM water for irrigation or disposal.
The document discusses the preparation of boiler feed water (BFW) from raw water. Raw water is processed through demineralization to remove minerals, producing demineralized (DM) water. DM water is further conditioned in a deaerator, where it is mixed with recycled condensate, heated with low pressure steam to remove dissolved gases, and oxygen scavengers like hydrazine are added to produce high quality BFW for use in boilers. Maintaining proper BFW quality through continuous and intermittent blowdown is important to minimize impurities in the boiler system and produce stable steam.
This document discusses challenges with cementing in deepwater environments, including shallow water flows and gas hydrate destabilization due to cement heat of hydration. It presents a solution of optimizing cement slurry design to reduce heat of hydration through lowering the calcium silicate reaction enthalpies. Experimental data shows that a cement system designed with a lower heat of hydration reduces temperature rise and develops strength rapidly enough to prevent issues. This optimized system was successfully implemented in the field to help prevent gas hydrate destabilization during cementing.
Key aspects of reservoir evaluation for deep water reservoirsM.T.H Group
The document summarizes key aspects of reservoir evaluation for deep water projects. It discusses challenges including geomechanics, reservoir characterization of thin beds and compartmentalization, and flow assurance requiring accurate fluid characterization. Reservoir characterization is identified as the biggest risk due to complex lithology, thin beds, and low contrast pay. Accurate fluid analysis and asphaltene characterization can help determine reservoir connectivity. Operator priorities include minimizing operational risk through rig efficiency and completion/production reliability. Reservoir evaluation is critical for deep water projects due to significant costs.
This document discusses cooling water treatment at a fertilizer plant in India. It provides details on the plant's cooling towers and water chemistry parameters. Cooling water treatment is needed to prevent corrosion, scaling, and microbial fouling of the system. Common issues like corrosion, scaling, and biofouling are discussed along with the mechanisms of corrosion inhibition, scale inhibition, and microbial control through chemical treatment.
Musings on potential CO2 migration along pre-existing (former) fluid flow pathways in the overburden - presentation by Andy Chadwick and Tom Bradwell of BGS at the UKCCSRC meeting Monitoring of the deep subsurface, 23 October 2014
S k-sharma-water-chemistry-in-thermal-power-plantsteddy tavares
The document provides an overview of water chemistry in thermal power plants. It discusses various water sources and treatment processes. Raw water undergoes clarification, filtration, and softening before being converted to demineralized water in the DM plant. This ultrapure water is used as boiler feed water. Cooling water chemistry is controlled to prevent scale, corrosion, and microbial growth. Proper treatment of waste streams can achieve zero liquid discharge from the plant.
Roger Howell is a principal hydrogeologist with over 30 years of experience in mining hydrogeology. He has worked on numerous projects involving hydrogeologic characterization, mine dewatering projections, and evaluating environmental impacts of mining. Some of the key projects mentioned in the document include studies for mines in the Philippines, Nevada, Argentina, Mexico, Alaska, Columbia, Saskatchewan, Nevada, Montana, Ontario, Utah, Northwest Territories, Peru, and Wyoming. The document provides an overview of Roger Howell's technical contributions and general approach to hydrogeologic studies for mining projects.
The document summarizes hydrogeological research on the impacts of proposed groundwater abstractions from the Merti Aquifer in Wajir, Kenya. Modeling shows drawdown from abstractions will likely not exceed 10 meters by 2050, which would not cause existing boreholes to run dry. However, upconing of saline water poses a risk of increasing borehole salinity. The risk depends on the unknown depth of the fresh-saline water boundary, with over 50% risk of salinization if it is less than 120 meters deep. Mitigation, like establishing the boundary depth or separating abstraction points, is needed to safely implement additional groundwater use from the aquifer. Dams and oil drilling
Uranium mill tailings are the residual wastes from milled ore after uranium extraction. They consist of slurries of sand and clay-like particles. Tailings are disposed of in specially engineered tailings impoundment systems, with various methods used for construction including upstream, downstream, and centerline dams. Tailings impoundments require long-term management to prevent environmental contamination through radiation, dust, and water pollution. Restoration techniques include stabilizing surfaces, providing covers, and monitoring effluents and the environment. Effective long-term management of uranium tailings wastes remains complex and problematic.
1) The document discusses potential impacts of proposed groundwater abstractions from the Merti Aquifer in Wajir, Kenya, including drawdown of water levels and increased salinity.
2) Modeling shows drawdown from abstractions will be less than 10 meters by 2050, which does not pose risks of drying boreholes. However, shallower existing boreholes could be impacted.
3) Increased salinity poses a more serious risk, with modeling finding a 50% risk of boreholes becoming saline by 2050 depending on the unknown depth of the fresh-saline water boundary. Mitigation, like establishing this boundary depth, is needed.
4) Upstream dams and oil
Reverse Osmosis module design and engineering emerged with membrane technology
evolution. In order to understand module design, first membrane configuration needs to be
explored, since the module design is always tailored according to the membrane
characteristics. There is a significant difference between membrane chemistries (most
important ones being cellulose acetate and thin film composite with polyamide barrier
layer), and more importantly, between the different membrane configurations (hollow fine
fiber and flat sheet). Therefore, before looking into detail on the module configuration, the
membrane development needs to be considered.
1. Water sources include surface water (oceans, rivers, lakes) and groundwater located beneath the Earth's surface.
2. Water can contain up to 90 possible contaminants including inorganic compounds, organic compounds, solids, gases, and microorganisms. Treatment depends on the water's chemistry and contaminants.
3. Hardness in water is caused by calcium and magnesium ions which prevents soap from lathering. It is classified as temporary (removable by boiling) or permanent (not removable by boiling) and is measured in units like ppm, mg/L, degrees, and meq/L. Hard water causes issues for domestic and industrial uses.
This document provides an overview of key concepts in petroleum engineering, including permeability, geophysics techniques for oil and gas exploration like seismic surveys, and reservoir engineering essentials. It discusses permeability measurement methods, factors that affect permeability, and types of permeability. It also summarizes different geophysics techniques like seismic surveys, gravity surveys, electromagnetic surveys, and magnetic surveys. Finally, it outlines the essential elements and processes for hydrocarbon accumulation, including the need for a trap, reservoir, source rock, and seal.
Incorporating the design features that were successful in the treatment capacity of the 1.2 acre wetland at the Flight 93 site for a typical flow = 775 gpm. The average percent removal was roughly 70% for iron and 50% for manganese within the wetland. This analysis allowed for a design foundation of the polishing aerobic wetland at the Clyde Mine Water Water Treatment Facility and the potential application at other mine water treatment locations where a relatively minor amount of polishing is needed to enhance iron and manganese removal for the final discharge.
The document summarizes a waterflood process for enhanced oil recovery using seawater injection. It discusses two options for pre-treating the seawater - sulfate removal membrane and nitrate injection. The nitrate injection process is selected, which involves filtration, deaeration, and injection of chemicals including nitrates, biocides, and corrosion inhibitors. A process flow diagram is presented showing the main unit operations for nitrate injection including filtration, deaeration, and multiple chemical injection points.
SiC Membranes for Produced Water TreatmentH2OSystems
H2O Systems SiC Membrane technology can treat produced water better than today's conventional free water knock out, skim tank, gas flotation technologies.
The document discusses drilling fluids, also known as drilling muds, which are pumped downhole during drilling operations. It covers the key functions and properties of drilling muds, including carrying cuttings, cooling the bit, controlling formation pressure, and creating a filter cake. The document also describes the various types of drilling muds such as water-based and oil-based muds. It provides details on mud components like weighting agents, viscosifiers, and additives used to control properties like viscosity, filtration, and shale stability. Measurement techniques for mud properties such as density, rheology, and gel strength are also summarized.
It is the welding process done under the water with the help of two methods : Dry Welding and Wet Welding. The presentation provides basic knowledge on the underwater welding and it's respective techniques.
The Groundwater and Storage interactions project arose out of a meeting on the shoulder of the Greenhouse Gas Technologies Conference in Amsterdam in 2010. It was decided to concentrate initially on the Australian Flagships projects. On 3 May 2011 Australian researchers and government agencies met and presented their work to date.
In these slides COLLIE HUB, Western Australia, present on Groundwater Issues
Similar to Wgc 2009 shtokman flow assurance rev07_no_backup (20)
1. Shtokman: the Management of Flow
Assurance Constraints in Remote
Arctic Environment
Erich Zakarian 1, Henning Holm 1, Pratik Saha 1, Victoria Lisitskaya 1
Vladimir Suleymanov 2
1 Shtokman Development AG, Russia
2 Gazprom VNIIGAZ, Russia
2. Contents
• The Shtokman field
• Shtokman Development AG
• Offshore challenges
• Field development - Phase 1 - FEED
• Offshore facilities
• Flow Assurance
• Risk identification & management
• Conclusions
3. The Shtokman field
• Two main sandstone reservoirs: J0 & J1
• Sweet & lean gas km
• 3.8 trillion Sm3 of natural gas (130 TCF) 0
65
• 37 million tons of condensate
• Water depth ~ 340 m
• Rough seabed
• Harsh metocean conditions
• Possible packed ice and icebergs
• Min. air temperature: -15°C / -38°C
• Min. seabed temperature: -1.8°C
4. Shtokman Development AG
• Special-purpose company for the integrated development of
the Shtokman gas-condensate field - Phase 1
• Joint venture between
• Responsible for engineering, financing, construction and
operation of Phase 1 installations
• Offshore facilities
• Onshore processing plant (LNG + gas treatment)
• Owner of infrastructures for 25 years
Annual production at wellhead = 23.7 billion Sm3 per year
5. Offshore challenges
• Sensitive ecosystem preserve the environment
• Extreme weather conditions winterization
• Ice threats ice management & disconnection
• Remoteness logistics constraints
• Huge production capacity (~70 MSm3/sd)
• Long-distance fluid transfer to shore
6. Field development - Phase 1
Front End Engineering and Design
Offshore facilities
7.
8. Flow Assurance risk identification
• Hydrate & ice formation
• Gas is saturated with water at reservoir conditions
• High reservoir pressure: approx. 200 bara in J0 and 240 bara in J1
• Low minimum ambient temperature: -1.8°C at seabed / -31°C onshore
• Corrosion, salt precipitation and scaling
• Corrosive agents (CO2, organic acids) and free water
• Formation water could be produced beyond year 10
• Sand production and erosion-corrosion
• Gas bearing sandstone reservoirs
• High volume flow rates
• Liquid accumulation and surges
• Three-phase flow (gas, condensate, water) in infield flowlines
• Dry two-phase flow (gas, condensate) in trunklines to shore
10. Hydrate & ice management
250
J0 J1
Hydrate dissociation curve
60 wt% MEG in water
200 Shut-in
(freezing point < -50°C)
conditions
Pressure [bara]
150
100
Hydrate dissociation curve
Raw natural gas
50
Infield subsea operating envelope
0
-30 -20 -10 0 10 20 30 40 50 60
Temperature [°C]
11. MEG loop design
• Subsea MEG injection
• Required MEG concentration in produced water = 60 wt% (rich MEG)
• Injection rates include uncertainties from reservoir temperature, water
saturation, MEG quality, flow measurement and distribution control
• Topside MEG regeneration
• Rich MEG from subsea is regenerated at 90 wt% (lean MEG)
• 85 wt% for the sizing of umbicals, injection pumps and chemical dosage
valves (CDV) to take account of MEG regeneration difficulties
• Salt management
• Rich MEG pre-treatment for low solubility salt removal (carbonates)
• Partial reclamation (40% slip stream) for high solubility salt removal (chlorides)
12. Corrosion and scale management
• Injection of film forming corrosion inhibitor at wellhead
• Commingled with regenerated MEG at topsides
• Injection of pH stabilizer at wellhead
• Possible for adjustment of the inhibition strategy
• Injection of scale inhibitor at wellhead
• Required at start-up of new wells (back-production of drilling and
completion fluids)
• Required at formation water breakthrough if residual presence of pH
stabilizer
• No risk of top of Line corrosion (TLC)
• Water condensation rate at top of line below 0.25 g/m2/s
• Small content of organic acids in condensed water (< 2 mmole/L)
13. Sand and solids free erosion-corrosion
• Sand control
• Lower well completion includes open hole gravel pack and sand screens
• Sand management and monitoring
• Subsea choke modules are equipped with sand detector
• Erosion & Momentum sensor at downstream of subsea chokes
• Well choking or shut-in when sand production is detected (alarm levels)
• Desanding system at MP separators
• Droplet erosion and erosion-corrosion management
• A maximum velocity is specified for each type of material
Corrosion resistant alloys (CRA): 50 m/s
Carbon steel (CS): Min (30 m/s, C/ρ1/2); ρ = fluid density; C =130 in US units
• Actual velocities: 10-35 m/s in CRA; 10-20 m/s in CS
14. Liquid management
• Liquid holdup
• Despite the roughness of the seabed, liquid accumulation in flowlines is
minimized by several factors:
Low liquid loading
High flowing velocities
Short length of infield flowlines (~ 2 km)
• Liquid holdup < 10 m3 in one flowline at the average flow rate of one well
• Slug catcher
• Adequate liquid surge capacity available within each inlet separator
• Designed for safe transient operations (ramp-up, restart, pigging)
16. Trunklines to shore
Gas is commingled with condensate
after dehydration and exported to shore
via 2 x 36” trunklines
• Dry two-phase flow
Robust alternative to 3-phase flow
Small impact on ΔP vs. 1-phase flow (very low liquid loading)
No requirement for offshore condensate storage
• Two trunklines
Flexible fluid transfer to shore
18. Pipeline profile discretization
• Two discretization methods were specially designed during FEED
• Essential characteristics of the original detailed pipeline profile are
conserved:
Length + Topography + Angle distribution + Total climb
• The hydrodynamic behavior of the original profile is conserved despite
significant data compression (2,500 points)
• Both methods are generic and can be applied to other developments
For more info: E. Zakarian, H. Holm and D. Larrey (2009), Discretization Methods for
Multiphase Flow Simulation of Ultra-Long Gas-Condensate Pipelines, 14th International
Conference on Multiphase Production Technology, Cannes, France, 16-19 June 2009
19. Liquid management
• Onshore finger-type slug catcher
• Total condensate buffer capacity = 2500 m3
• Designed for safe transient operations (ramp-up, restart, pigging)
• Operating philosophy
• The produced condensate is preferably allocated to the trunkline
with the maximum throughput
• Pipeline management system (PMS)
• After first gas, operating procedures will be adjusted with the
support from multiphase dynamic simulation
20. Hydrate and corrosion management
• Fluid dehydration
• To avoid the presence of free water and the need for chemical inhibitors
• Ambient conditions
• Offshore: sea temperature is about -1.8°C in winter (1°C in summer)
• Onshore: minimum air temperature can be very low: -31°C
• Insulation?
• Offshore: NO to maintain fluid temperature close to ambient temperature
• Onshore: YES to provide robust pipeline insulation and protection
• Dehydration specification
• Stringent specs for potential upset in condensate dehydration process
• Gas: 5 ppm vol water
• Condensate: 100 ppm vol water
21. Conclusions
• The development of remote gas resources in the Arctic will
require specific engineering
• A robust design is proposed to manage Flow Assurance
risks in the 1st development phase of the Shtokman field
• This work can serve as a reference for the development of
other remote resources in the Arctic