The document discusses the concept of skin factor in wellbore flow, which is a dimensionless quantity that describes flow efficiency. A positive skin factor indicates damage that restricts flow, while a negative skin indicates flow enhancement. Skin can result from various factors like partial completion, damage near the wellbore, hydraulic fracturing, or deviation of the well from vertical. Equations are provided to calculate the pressure drop and flow efficiency based on the skin factor. The total skin is the sum of individual skin components from different sources like damage, completion, deviation etc.
After drilling is completed, wells undergo completion procedures to prepare them for production. This involves setting production casing and cementing it through the target zone. Tubing is run inside the casing with a packer to isolate the production zone. A Christmas tree is installed to control flow. Completion types include open hole, liners, and perforated casing. Perforating creates holes through casing into the formation. Some formations require stimulation like acidizing to improve permeability or fracturing to create conductive fractures held open by proppant. This increases flow into the wellbore.
The document discusses drilling fluids or mud, which are fluids circulated during drilling operations. There are several types of drilling fluids including water-based, oil-based, foam-based, and synthetic-based fluids. Drilling fluids serve various important functions including removing cuttings from the well, controlling formation pressure, maintaining wellbore stability, minimizing damage to the reservoir, and cooling and lubricating the drill bit. The appropriate type of drilling fluid depends on factors like the desired performance, environmental considerations, safety, cost, and availability. Water-based and oil/synthetic-based fluids are described in more detail. The document also outlines various properties and tests used to analyze the characteristics of drilling fluids.
about 70 % of the existing reservoirs are impossible to reach with conventional drilling . MPD or managed pressure drilling is the best solution for HPHT and very deep reservoirs .
Drilling fluids are absolutely essential during the drilling process and considered the primary well control.
Know more now about such a very important component of the drilling process.
This document discusses drilling fluids and their properties. It provides an overview of the principal functions of drilling fluids, which include subsurface pressure control, cuttings removal and transport, suspension of solid particles, sealing of permeable formations, stabilizing the wellbore, preventing formation damage, cooling and lubricating the bit, transmitting hydraulic horsepower to the bit, facilitating collection of formation data, partial support of the drill string and casing weights, controlling corrosion, and assisting in cementing and completion. It also discusses drilling fluid classifications, properties such as viscosity and rheology, and key components of drilling fluids.
This document discusses well testing and well test analysis software programs. It provides information on:
- The objectives of well testing including identifying fluid types and reservoir parameters
- Types of well tests including productivity tests for development wells and descriptive tests for exploration wells
- Popular well test software programs for analytical and numerical analysis including Saphir, PanSystem, Interpret 2000, and Weltest 200
- An overview of the Weltest 200 program which links analytical and numerical well test analysis through different modules
- Using an example of liquid productivity or IPR testing to demonstrate how well test data is incorporated and analyzed in the software
The document discusses formation damage in oil and gas wells. It defines formation damage as a reduction in permeability of the reservoir rock surrounding the wellbore. Several mechanisms of formation damage are described, including plugging by solids, clay swelling, saturation changes, and bacterial growth. Methods for evaluating formation damage in the field include well testing, downhole video, sampling fluids and solids, and coring. The concept of skin factor is introduced to quantify the level of damage. Laboratory studies on formation damage at different drilling environments are also summarized.
This document provides an overview of a mud engineer trainee's work experience with two rigs, DQE-32 and DQE-51. It discusses the functions of drilling fluid, types of mud, testing procedures, chemical categories used in mud systems, calculations, cementing operations, formation and downhole problems, and general mud engineering information. The trainee thanks their mentors at Petrochem for providing training support over their 3-month internship.
Primary cementing involves placing cement between the casing and borehole to isolate zones and support the casing. It involves running casing, circulating mud, pressure testing, pumping wash/spacer, mixing and pumping cement slurry, and displacing with fluid. Secondary cementing, like squeeze cementing, is used to repair improper zonal isolation, eliminate water intrusion, or repair casing leaks by pumping cement through perforations or casing leaks. It can be done with low or high pressure placement using techniques like running squeeze or hesitation squeeze to fill perforations or fractures.
This document discusses drilling fluids, including their types, functions, properties, and additives. It covers the main types of drilling fluids as water-based and oil-based, and their key functions such as removing cuttings from the wellbore, maintaining wellbore pressure and stability, lubricating and cooling the drill bit. The most common additives are described, including weighting materials to increase mud density, viscosifiers to suspend cuttings and materials, and other additives that control filtration, rheology, alkalinity and other properties. Selection of the appropriate drilling fluid depends on formation data and requirements for each well section.
This document discusses workover operations in oil and gas wells. It begins by defining workover as any operation done within or through the wellbore after initial completion to address problems and fulfill the well's purpose over its lifetime. Common reasons for workovers include unsatisfactory production rates, mechanical failures, supplementary recovery projects, and reducing water or gas production. The document then examines different types of workover operations such as installing artificial lift, water shutoff techniques, casing repairs, zone transfers, and well abandonment. It also covers well stimulation and testing procedures.
Drilling operations can encounter various problems related to geological uncertainties, wellbore stability issues, and depletion effects. Some key risks include uncertainties in pore pressure-fracture gradient measurements, mud volcanoes causing landslides or weak formations, fault zones providing pathways for fluid flow, and maintaining wellbore integrity in low-pressure depleted zones. Operators address these challenges through careful planning, identifying potential hazard areas using seismic data, selecting appropriate drilling fluid properties, and employing wellbore strengthening techniques and lost circulation materials when needed to prevent fluid losses and wellbore collapse.
Este documento describe diferentes tipos de fluidos de perforación, incluyendo fluidos basados en agua, lignosulfonatos, cal, polímeros y fluidos viscoelásticos. Explica las clasificaciones, propiedades y usos de cada tipo de fluido.
This document provides an overview of basic well control procedures including:
- Kick detection and control methods like primary prevention and secondary detection and control
- Shut-in procedures such as hard, soft, and specialized shut-ins
- Well kill procedures including calculating initial and final circulating pressures, the wait-and-weight/engineer's method, and providing an example pump schedule.
It describes the key objectives and considerations for safely controlling a well when kicks occur and bringing the well pressure to a controlled state.
16 evaluación de las cementacion05 pruebas de laboratorio para los cement...AgustÍn Piccione
Este documento describe los principios básicos de los registros sónicos (CBL) para la evaluación de cementaciones. Explica que las ondas acústicas viajan a través del revestimiento y el cemento, y que la amplitud de la señal recibida depende de la adherencia entre estos materiales. También analiza cómo factores como canales de lodo, contaminación del cemento y falta de adherencia pueden afectar la interpretación de la amplitud. Concluye que la evaluación del CBL requiere una interpretación cuidadosa y el uso de múltiples mé
This document provides information about well completion processes and equipment. It discusses steps like well clean up, mud displacement, perforating, and installing downhole equipment like packers, landing nipples, and side pocket mandrels. The document also outlines considerations for completion design based on factors like the wellbore, reservoir properties, and production method. Well completion aims to enable production from the reservoir to the surface.
DAMAGE ISSUES IMPACTING THE PRODUCTIVITY OF TIGHT GAS PRODUCING FORMATIONS; Formation Damage; Fracturing/Refracturing; Hydraulically Fractured; Tight Gas Reservoir; Economic Tight Gas Reservoir Production
Blowout preventers are critical well control equipment used to seal the wellbore. They consist of valves attached to the wellhead that can seal around drill pipes or close the wellbore entirely. The document discusses the types of blowout preventers, criteria for selection, specifications including sizes and pressure ratings, components like ram and annular blowout preventers, and testing procedures to ensure proper operation. Function tests are performed weekly to verify components can close and seal within specified time limits using stored accumulator pressure.
Cement Slurry Design for Oil and Gas Well CementationHimanshu Rajawat
This document summarizes cement slurry design for oil and gas well cementation. It discusses the objectives of cementing including zonal isolation and wellbore support. Key factors in cement slurry design are well parameters like depth, temperature and pressure. Important slurry parameters include density, thickening time, rheology, fluid loss and compressive strength. Cement additives like accelerators, retarders, dispersants and fluid loss additives are used to modify slurry properties for different well conditions. Laboratory equipment used in slurry testing and evaluation are also outlined.
The document discusses the use of formate brines, specifically cesium formate brine, as drilling, completion and suspension fluids for deep, high pressure high temperature (HPHT) gas wells. Cesium formate brine provides benefits such as stability at high temperatures, compatibility with reservoirs, and less corrosion and damage compared to other brines. It has been used successfully in over 50 HPHT gas field developments worldwide, enabling improved well construction methods like open hole completions.
This document summarizes directional drilling services including positive pulse telemetry, electromagnetic telemetry, pressure while drilling, gamma tools, and motor services. Key features highlighted are robust equipment, minimized asset loss through retrievability, customizable survey times, and adaptability to various flow rates. Well planning services are also listed such as horizontal wells, multi-laterals, re-entries, survey systems, torque and drag analysis, and managed pressure drilling.
Ahmed Mohamed Salah Mohamed El-Sagheer's curriculum vitae provides his personal and contact information, education history including a BSc in Commerce from Ain Shams University, and employment history working for Belayim Petroleum Company since 2000 in procurement and project roles. He has extensive training and computer skills qualifications supporting his procurement responsibilities.
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.
A walk from Land's End to Launceston, in easy 8- to 9- mile stages, on minor roads and footpaths. The walk on Day 7 was from Victoria Services to Cardinham Woods outside of Bodmin
A Ramble Through Cornwall - Day 6 - St Stephen to Victoria (Bodmin) John Downs
Describes the 6th of a 10-day walk through Cornwall from Lands End to Launceston in easy 9-mile stages on minor roads and footpaths. This walk on Day 6 was from St Stephen to Victoria near Bodmin.
This document summarizes a presentation on the use of formate brines for deep gas field development projects. It finds that formate brines provide operational efficiencies over conventional drilling fluids by providing a more stable wellbore, faster tripping speeds, and fewer well control incidents. These efficiencies can reduce well construction costs and times. The document also finds that fields developed using only formate brines were able to recover 90% of reserves within 7-8 years, indicating formate brines may enable more efficient production.
HPHT (High Pressure - High Temperature) wells have a downhole environment of more than 10,000psi (690 bar) and/or 300 deg F (140 deg C). These conditions are increasingly encountered in many basins worldwide, as exploration and production examine deeper and hotter objectives.
In attending this course, participants will gain knowledge and develops skills relating to HPHT Well Engineering. The course focuses on key characteristics and challenges of HPHT wells from well design, planning, engineering and operational perspectives.
This document discusses the challenges of drilling fluids for deep oil well drilling. As drilling depths increase and harder rock is encountered, drilling fluids must be able to withstand higher pressures and temperatures. Developing "smart" drilling fluids that can adapt to harsh conditions and have properties accurately measured is a focus. Rheology is particularly important and affected by downhole pressure and temperature. Models are needed to predict conditions downhole and evaluate drilling fluid performance to ensure efficient cuttings removal and wellbore stability in extreme environments.
Numerical Study of Strong Free Surface Flow and Wave BreakingYi Liu
1. The document describes numerical methods for simulating strong free surface flows and wave breaking, including the coupled level set and volume-of-fluid method.
2. Results are presented from simulations of breaking waves under different wind conditions, showing the generation of vortices and effect of wind speed on wave breaking.
3. Future research topics discussed include studying wave breaking mechanisms under different conditions, the interaction of wind turbulence and breaking waves, and multi-scale simulations of wind-wave-structure interaction using immersed boundary methods.
The document discusses the use of cesium formate brine as a drilling fluid for drilling deep high pressure, high temperature (HPHT) gas wells over the past 10 years. Some key points:
1) Cesium formate brine is an effective drill-in and completion fluid for HPHT gas wells that is non-toxic, compatible with reservoirs, and less corrosive than other brines.
2) It has been used successfully in over 42 HPHT gas fields worldwide to drill and complete wells with maximum reservoir temperatures up to 320°F.
3) Specifically, cesium formate brine has enabled operators to construct high-angle open hole screen completions in HPHT reservoirs
Developing smart drilling fluids that can adapt to harsh downhole conditions with extreme pressures and temperatures over 7,000 meters deep is challenging. Drilling fluid must maintain stable density and rheology at these conditions while transporting cuttings and cooling drill bits. Improved rheological models and hydraulics modeling are needed to better predict downhole pressure and optimize fluid properties. Additives also need to be developed that can withstand the hostile environments encountered during deep drilling.
This document discusses drilling fluid systems. It provides information on:
- Drilling fluid functions such as providing hydrostatic pressure, keeping the drill bit cool, carrying cuttings, and limiting corrosion.
- Types of drilling fluids including water-based mud, oil-based mud, and synthetic-based mud.
- Components of an active drilling fluid system including pumps, pits, and the annular space in the wellbore.
- Factors that determine drilling fluid volume such as rig size and well design/depth.
- Rheological behavior models for drilling fluids based on relationships between shear stress and shear rate.
- Uses of drilling fluid rheology including calculating friction and surge pressures.
- Instruments for
The document summarizes a student project on shrinkage in cementation of high pressure and high temperature wells. It was conducted at the Institute of Drilling Technology of Oil and Natural Gas Corporation in Dehradun, India under the guidance of Dr. Kishori Lal. The project involved characterizing cement bonding performance and evaluating properties of cement slurries like fluid loss and permeability. It aimed to provide solutions to shrinkage in oil well cement at high pressure and high temperature conditions. Laboratory experiments were conducted to compare bonding and properties of standard cement compositions with modified compositions containing additives.
This document provides an overview of drilling fluid classifications and their functions. It discusses pneumatic, oil-based, and water-based fluids. The major functions of drilling fluids include controlling subsurface pressure, transporting cuttings, and supporting and stabilizing the wellbore. The document also outlines basic engineering calculations for drilling fluids, such as specific gravity, volume, capacity, pressures, weight-up and dilution calculations. It provides testing procedures for water-based and oil-based drilling fluids.
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 provides an overview of petroleum drilling fundamentals, including different types of rigs used for offshore drilling. It discusses jack-up rigs, semi-submersible rigs, drill ships, condeep platforms, jacket platforms, and tension leg platforms. It also covers well planning, designing the well, drilling operations, completions, new technologies, and structural geology. Key steps in drilling include obtaining licenses, exploration, appraisal, development, maintenance, and abandonment of oil and gas fields. Safety and monitoring drilling progress are also emphasized.
This document summarizes the results of a survey sent to HPHT professionals regarding challenges in HPHT operations. According to the survey results, the biggest technology gaps are in cement design and performance, seals, and tubulars. The major challenges with equipment durability are reliability under extreme conditions, dynamic seals, and material failure due to high temperature. Ensuring electronic survivability requires considering temperature, pressure, shock, and vibration. While more is being done to address risks, over half of respondents felt not enough is being done to combat product failure at high temperatures. Key factors for successful QA/QC include thoroughness, testing under realistic conditions, and root cause analysis.
This document discusses bentonite, its origins, and its use in drilling fluids. Bentonite is a volcanic ash that was formed during the Cretaceous Period and is found in large volumes in the western U.S. It is composed of stacked platelets that can absorb large quantities of water and expand up to 20 times its original volume. Bentonite is used as the base material for drilling fluids due to its ability to suspend cuttings and form a filter cake to control fluid loss. Polymers and other additives are used to modify the properties of bentonite drilling fluids for different soil conditions.
The document discusses the use of formate brines, specifically cesium formate brine, as drilling, completion and suspension fluids for deep, high pressure high temperature (HPHT) gas wells. Cesium formate brine provides benefits such as stability at high temperatures, compatibility with reservoirs, and less corrosion and damage compared to other brines. It has been used successfully in over 50 HPHT gas field developments worldwide, enabling improved well construction methods like open hole completions.
Potassium formate brine has been successfully used as a drilling and completion fluid in hundreds of high-pressure, high-temperature gas wells since 1995. It has allowed for improved economics by reducing well delivery times and costs while improving safety. Key applications include drilling reservoir sections, completions, workovers, and suspension of wells. Countries where it has been used extensively include Germany, Norway, the UK, Pakistan, Saudi Arabia, and others. Its use has helped develop major gas fields like the HPHT fields in Northwest Germany and the world's largest gas field, Kashagan in Kazakhstan.
SPE 165151 - The Long-term Production Performance of Deep HPHT Gas Condensat...John Downs
Formate brines have been in use since 1995 as non-damaging drill-in and completion fluids for deep HPHT gas condensate field developments. The number of HPHT fields developed using formate brines now totals more than 40, and includes some of the deepest, hottest and highly-pressured reservoirs in the North Sea. The well completions have been both open-hole and cased-hole.
An expectation from using formate brines as reservoir drill-in and completion fluids is that they will cause minimal damage to the reservoir and help wells to deliver their full productive potential over the life-time of the field. The validity of this expectation has been tested by examining the long-term hydrocarbon production profiles of eight HPHT gas condensate fields in the North Sea where only formate brines have been used as the well completion fluids. In five of these fields the wells were drilled with oil-based muds and completed by perforating in cased hole with high-density formate brines. In another two of the fields the wells were drilled with formate brines and completed with screens entirely in open hole using the same brines. The last of the eight fields was drilled with formate brine and the wells were then completed with same fluid in either open hole or cased hole.
The results of the production analysis provide a unique insight into the impact of a single type of specialist drill-in and completion fluid on the rate of recovery of hydrocarbon reserves from deeply-buried reservoirs in the North Sea
Cementing is an essential part of the oil and gas drilling process. It is used to provide zonal isolation in a wellbore, creating a barrier between different zones and preventing production fluid from entering unwanted formation areas.
SPE 199286 - Profiling the Production Performance of Five HPHT Gas Condensate...John Downs
1. The document discusses production performance from five high-pressure, high-temperature gas condensate wells in the Kvitebjorn Field in the Norwegian North Sea that were drilled and completed using cesium formate drilling fluids.
2. Logging data obtained using cesium formate brine showed improved reservoir quality, leading to a 33% increase in estimated hydrocarbon reserves. Actual cumulative production from the field has matched or exceeded revised reserve estimates.
3. Cumulative production from the initial five wells after 14 years is now higher than the original reserves projection for the entire field, demonstrating the benefits of using cesium formate fluids for drilling and completion.
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 provides information about Shinjin Engineering Co., including:
- Their history and capabilities in areas such as gas and water treatment, piping, and fabrication.
- Their organization chart and staff experience/qualifications.
- Example projects they have completed for customers like ExxonMobil, Total, and Samsung.
- Their partnership with Kanfa Ingenium Process, which provides process design expertise to complement Shinjin's detailed engineering and project management capabilities.
This document provides an overview of Bhartia Group, an Indian conglomerate operating in various industries. It details the group's core businesses which include manufacturing additives for foundries, cement, packaged drinking water, coke, HDPE bags, medical gases, mining, trading, retail, farming, and real estate development. The group aims to meet evolving societal and market expectations through diversification and has offices across India and internationally. It primarily manufactures products that support foundry operations such as additives, coatings, inoculants, and ferro alloys.
Cesium formate brine has been used as a completion and perforation fluid in 15 wells across 11 high-pressure, high-temperature (HPHT) gas fields in the UK sector of the North Sea since 1999. It was first used in Shell's Shearwater field and then Total's Elgin/Franklin field, the world's largest HPHT field. Since then it has been used in 12 additional HPHT wells in various fields. Production rates from wells completed with cesium formate brine have ranged from 1.6 to 2.6 million cubic meters per day. Some individual wells have achieved over 30,000 barrels of oil equivalent per day. Thirteen years after its first use, cesium
This document discusses the use of cesium formate brine as a drilling, completion, and workover fluid for high pressure, high temperature (HPHT) gas wells over the past 10 years. Some key points:
- Cesium formate brine is non-toxic, compatible with reservoirs, and less corrosive than other brines like bromide brines.
- It has been used successfully in over 40 HPHT gas fields worldwide, enabling improved well control and safer drilling operations compared to other fluids.
- Specific examples from the North Sea highlight its effectiveness as a combined drill-in and completion fluid, resulting in low skin factors and high well productivity.
This document provides an overview of gas processing technology through a 67 slide presentation. It discusses the need for gas processing due to impurities from geological formations. The presentation focuses on onshore gas processing technologies and concepts like centralized and decentralized approaches. Key processing steps discussed include crude oil stabilization, slug catching, gas sweetening using various solvents to remove acid gases, and other downstream processes like dehydration and NGL/LPG recovery. Equipment used in gas sweetening like contactors, strippers and amine circulation are also outlined.
Sandvik process systems kumar swamy (paper)KVVKSwamy
1. The existing AN and NPK facilities at Azomures in Romania were outdated and needed modernization to produce higher quality products that could attract higher prices internationally.
2. Sandvik evaluated prilling, granulation, and their Rotoform technology as alternatives for modernizing the AN and NPK finishing processes.
3. Rotoform offered several advantages over prilling and granulation, including lower energy consumption since it does not require large air flows, no need to manage ammonium nitrate dust emissions, and production of a solid product with a narrow size distribution without additional screening or crushing equipment. As a result, Azomures decided to invest in two Rotoform HS 2000 lines.
CEMENT , TYPES OF CEMENTS , PORTLAND CEMENT
TYPES OF PORTLAND CEMENT, GENERAL FEATURES OF THE MAIN TYPES OF PORTLAND CEMENT, ORDINARY PORTLAND CEMENT (OPC), RAPID HARDENING PORTLAND CEMENT, SPECIAL TYPES OF RAPID HARDENING PORTLAND CEMENT, MANUFACTURE OF PORTLAND CEMENT, Raw Materials, Crushing & Grinding of Raw Materials,Type of cement processes, Wet Process, Dry process, Burning Process, Grinding, storage, packing, dispatch,CEMENT CHEMISTRY,Chemical Compositions,Bogue’s Equations, Fineness of cement
The document provides information on a dissertation project carried out to improve productivity and quality in the production of 7-series grades of carbon black at M/s Hi-Tech Carbon in Renukoot, India. The project involved collecting data on existing grit levels, analyzing potential causes of high grit through a why-why analysis, identifying the root cause using a Pareto diagram, developing and implementing a trial plan with actions to address the root cause, and achieving improved performance with grit levels reduced and Cpk values increased after regular implementation.
SPE 145562 - Life Without Barite: Ten Years of Drilling Deep HPHT Gas Wells ...John Downs
The tradition of using barite to increase the weight of drilling fluids dates back to the early-1920’s and, while it has been of great benefit to the oil industry over the past 90 years, it has also caused some chronic and persistent well construction problems along the way. These problems, which are very familiar to drillers, include well control difficulties, stuck pipe incidents and formation damage.
The oil industry has known since the 1970’s that replacing barite with suitable non-damaging solutes in reservoir drill-in fluids is an effective way of reducing formation damage, simplifying operations and eliminating the need for expensive formation damage by-pass operations. The development of brine-based drill-in fluids opened up the opportunity to connect more effectively with hydrocarbon reserves by allowing the construction of long high-angle reservoir sections completed in open hole. Despite the advantages on offer, the industry was unable to exploit this novel technology in deep HPHT gas field developments until the mid- to late-1990’s when drill-in fluids based on potassium and cesium formate brine became available in commercial volumes.
Cesium formate brine was first used as a reservoir drilling fluid in the Huldra gas/condensate field in the North Sea in January 2001, and has now been used to drill a total of 29 deep HPHT gas wells. The information presented and reviewed in this paper confirms that the use of potassium and cesium formates as the sole weighting agents in reservoir drill-in fluids has enabled operators to enjoy the full economic benefits of creating low-skin open-hole completions in deep high-angle HPHT gas wells. The review also concludes that the use of these heavy formate brines as drill-in fluids over the past 10 years has facilitated the safe and efficient development of deep HPHT gas reserves by:
• Virtually eliminating well control and stuck pipe incidents
• Enabling the drilling of long high-angle HPHT wells with narrow drilling windows
• Typically reducing offshore HPHT well completion times by 30 days or more
• Improving the definition and visualization of the reservoirs
• Eliminating the need for clean-ups, stimulation treatments or any other form of post-drilling well intervention to remove formation damage caused by the drilling fluid
This has all been made possible by the operators’ acceptance and adoption of the award-winning Chemical Leasing (ChL) and fluid management programmes that form the basis of their contracts with the sole producer of cesium formate brine. The use of the ChL model has played an important role in reducing the unnecessary consumption of what is a very rare and valuable chemical resource
As the oilfield industry is soaring new heights with each passing day owing to the increase in demand of the
petroleum based products today, simultaneously, the need of completion fluids is also escalating with same pace.
Amongst the completion fluids, the most commonly used components are Completion 14.2™, Completion 12.5™ and
Completion 19.2™. Consequently, there is a rising demand for the preparation of these chemical components or
rather the completion fluids in order to cater to the needs of the oilfield industry for carrying out the drilling
operations required in oil and gas exploration projects.
Similar to Formate Brines - Reservoir drilling and well completion fluids since 1993 (20)
SPE 24973 35 mm slides in Powerpoint .pptxJohn Downs
Scanned copies of the original 35 mm slides used in the presentation of SPE paper 24973 by John Downs of Shell at the European Petroleum Conference held in Cannes, France, 16-18 November 1992
Single cell protein (SCP) from methane and methanol - publications from Shell...John Downs
The Fermentation and Microbiology (FMB) department of Shell Research Centre in Sittingbourne was a leader in the development of single cell protein (SCP) production from methane and methanol in the 1970's. This updated presentation lists virtually all of the publications from the Shell scientists engaged at that time in the development of a single cell protein production process using methane and methanol as the carbon feedstocks. Their main focus was growing Methylococcus capsulatus in continuous culture on methane.
A Walk Through Devon - Day 6 - Morchard Bishop to Five Crosses John Downs
Day 6 of an 8-day walk through Devon. An 8-mile walk from Morchard Bishop to Five Crosses on a route that could be used by Lands End to John O'Groats long distance walkers passing through the county
A Walk through Devon - Day 5 - Bondleigh Bridge to Morchard Bishop John Downs
Day 5 of an 8-day walk through Devon. An 8-mile walk from Bondleigh Bridge to Morchard Bishop on a route that could be used by Lands End to John O'Groats long distance walkers passing through the county
A Walk through Devon - Day 4 - Stockley Hamlet (Okehampton) to Bondleigh BridgeJohn Downs
Day 4 of an 8-day walk through Devon. An 8-mile walk from Stockley Hamlet to Bondleigh Bridge on a route that could be used by Lands End to John O'Groats long distance walkers passing through the county
Day 2 of a walk through Devon - From Lewdown to Bridestowe. The entire set of " A Walk through ..." walks currently covering the south-west of England from Lands End up into the Cotswolds could be used as a route guide by Lands End-John O'Groats (LEJOG) walkers
Day 1 of a walk through Devon - From Launceston on the Cornwall /Devon border to Lewdown in Devon. The entire set of " A Walk through ..." walks currently covering the south-west of England from Lands End up into the Cotswolds could be used as a guide by Lands End-John O'Groats (LEJOG) walkers
A Ramble through Cornwall - Day 8 - Bodmin to St Neot John Downs
A short (7 mile) walk from the outskirts of Bodmin east to St Neot, skirting the southern border of Bodmin Moor. Mostly walking in fog on this particular day
This document summarizes the key findings of a study on the effects of different well construction fluids on rig time savings. The study analyzed 89 North Sea wells and found that switching from oil-based muds to cesium or potassium formate fluids can save up to 26 days of rig time. Specifically, using formate fluids for open-hole standalone sand screen completions can save over 3.5 weeks compared to cased and perforated completions using oil-based muds. Formate fluids also significantly reduce completion times for both well construction techniques and increase drilling rates of penetration compared to oil-based muds.
DMK chose potassium formate brines over invert oil-based muds for drilling long horizontal wells in the abrasive Montney shales. They experienced significant cost and time savings from increased drilling rates of penetration (ROP), longer bit life, improved wellbore cleaning, and lower equivalent circulating densities (ECDs). Operators saw ROP improvements of 30-50% and bit runs twice as long as with oil-based muds. Using solids-free potassium formate brine allowed excellent horizontal wellbore cleaning without cuttings beds forming and reduced circulating pressures.
Open-hole sand-control completions using expandable sand screens (ESS) offer advantages over traditional cased-hole completions including improved production rates and lower installation costs. The documents discusses several case studies where formate brines and ESS were used together, setting world records for longest, hottest, and deepest ESS installations. This included projects by Shell in the Brigantine field in the UK North Sea and by Saudi Aramco in the K-field in Saudi Arabia, improving well economics in both cases.
This document summarizes Cabot Specialty Fluids' (CSF) sustainable business model of leasing cesium formate brines and retaining ownership of the chemicals. This model encourages efficiency by charging clients based on time used rather than consumption. It also aligns incentives between CSF and clients to minimize waste. The model has proven successful, with CSF normally recovering 80-85% of leased brines. The document notes UNIDO's support for innovative concepts like CSF's model that reduce chemical consumption and waste. CSF was honored with a UNIDO award for its contributions to advancing chemical leasing programs.
The document discusses eco-efficiency analysis conducted by BASF to compare the eco-efficiency of formate brines and bromide brines. The analysis found that formate brines were significantly more eco-efficient than bromide brines. Formate brines scored better on costs, lower toxicity potential, and lower emissions. In particular, bromide brines produced large amounts of toxic waste that required special treatment. While formate brines required more salt overall, they offered a more sustainable solution for the scenario of completing a well in the North Sea. BASF concluded that formate brines were the most eco-efficient option based on both environmental and economic factors.
leewayhertz.com-AI agents for healthcare Applications benefits and implementa...alexjohnson7307
In recent years, the integration of artificial intelligence (AI) in various sectors has revolutionized traditional practices, and healthcare is no exception. AI agents for healthcare have emerged as powerful tools, enhancing the efficiency, accuracy, and accessibility of medical services. This article explores the multifaceted role of AI agents in healthcare, shedding light on their applications, benefits, and the future they herald.
RPA In Healthcare Benefits, Use Case, Trend And Challenges 2024.pptxSynapseIndia
Your comprehensive guide to RPA in healthcare for 2024. Explore the benefits, use cases, and emerging trends of robotic process automation. Understand the challenges and prepare for the future of healthcare automation
How Social Media Hackers Help You to See Your Wife's Message.pdfHackersList
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Formate Brines - Reservoir drilling and well completion fluids since 1993
1. FORMATE BRINES
DRILL-IN AND COMPLETION FLUIDS SINCE 1993
John Downs
Formate Brine Ltd
www.formatebrine.com
2. Formate brines
Sodium
formate
Potassium
formate
Cesium
formate
Solubility in
water
47 %wt 77 %wt 83 %wt
Density 1.33 g/cm3
11.1 lb/gal
1.59 g/cm3
13.2 lb/gal
2.30 g/cm3
19.2 lb/gal
Formates are also soluble in some non-aqueous solvents
2 John Downs - Formate Brine Ltd
3. LATEST FORMATE SUCCESS – Unconventional
shale drilling – Formates cut drilling times in half
Oil companies in Canada are exploiting a discovery from
1996 – formates are VERY fast in shale vs weighted
muds
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4. Potassium formate brines excelling in Canada
as solids-free and polymer-free shale drilling fluid
118 shale wells drilled with DMK’s potassium formate
drilling fluid since mid-2013
Quote from Encana : “ The fluid is inhibitive, after drilling caliper logs displayed the
same response as invert (oil) drilled caliper logs. The ROP improvement has
allowed us to cut our lateral drilling time in half! “
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5. New explanation for shale drilling success with
potassium formate – Osmosis
Paper to be presented to the 2015 SPE/IADC Drilling conference :
ROP Enhancement in Shales through Osmotic Processes
Eric van Oort, SPE, and Muneeb Ahmad, The University of Texas at Austin, and
Reed Spencer, SPE, Baker Hughes
“It will be shown that the mechanism responsible for the Deeptrek ROP results
with formate mud is chemical osmosis …..”
Potassium formate brine use in unconventional shale drilling
may become widespread
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6. The traditional use for formate brines is in
High-Pressure High-Temperature gas wells
Low-solids heavy fluids for deep HPHT gas well constructions
• Reservoir drill-in
• Completion
• Workover
• Packer fluids
• Well suspension
• Fracking
Used in hundreds of HPHT wells since 1995, including some of
Europe’s deepest, hottest and highly-pressured gas reservoirs
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7. 42 deep HPHT gas fields developed using formate
brines , 1995-2011. Now probably > 50 fields *
Country Fields Reservoir Description
Matrix
type
Depth, TVD
(metres)
Permeability
(mD)
Temperature
(oC)
Germany Walsrode,Sohlingen
Voelkersen, Idsingen,
Kalle, Weissenmoor,
Simonswolde
Sandstone 4,450-6,500 0.1-150 150-165
Hungary Mako , Vetyem Sandstone 5,692 - 235
Kazakhstan Kashagan Carbonate 4,595-5,088 - 100
Norway Huldra ,Njord
Kristin,Kvitebjoern
Tune, Valemon
Victoria, Morvin,
Vega, Asgard
Sandstone 4,090-7,380 50-1,000 121-200
Pakistan Miano, Sawan Sandstone 3,400 10-5,000 175
Saudi Arabia Andar,Shedgum
Uthmaniyah
Hawiyah,Haradh
Tinat, Midrikah
Sandstone
and
carbonate
3,963-4,572 0.1-40 132-154
UK Braemar,Devenick
Dunbar,Elgin
Franklin,Glenelg
Judy, Jura, Kessog
Rhum, Shearwater
West Franklin
Sandstone 4,500-7,353 0.01-1,000 123-207
USA High Island Sandstone 4,833 - 177
* More HPHT fields developed in Kuwait, India and Malaysia during 2012-2013
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8. Almost every HPHT gas field in northern North Sea in
Norway drilled and/or completed in formate brine
More than 400 well construction jobs in Europe with high density formate
brines since 1995
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9. Formate brines as packer fluids in USA (GOM)
OPERATOR LOCATION
Packer Fluid
(ppg)
BHT
(°C)
BHT
(°F)
Start
Date
End
Date
Comments
Devon WC 165 A-7 8.6 KFo 149 300 1/2005
Devon WC 165 A-8 8.6 KFo 149 300 1/2006
Devon
WC 575 A-3
ST2
9.5 KFo 132 270 5/2005
WOG/Devon MO 862 #1 12.0 NaKFo 215 420 4/2005 5/2006
Well P&A – H2O
production – G-3 in
excellent condition
BP/Apache HI A-5 #1 11.5 NaKFo 164 350 2/2002 4/2008
Well P&A - Natural
depletion – S13Cr in
excellent condition
ExxonMobil MO 822 #7 12.0 NaKFo 215 420 2001
EPL ST 42 #1 11.5 NaKFo 133 272 2006
EPL ST 41 #F1 13.0 NaKFo 105 222 2006
EPL EC 109 A-5 11.5 NaKFo 121 250 2006
EPL ST 42 #2 12.8 NaKFo 132 270 2006
Dominion
WC 72 #3
BP1
10.0 NaFo 121 250 2006
EPL
WC 98 A-3
ST1
12.7 NaKFo 153 307 2006
EPL WC 98 A-3 10.8 NaKFo 154 310 2007
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10. BP High Island, Gulf of Mexico – Formate
brine used as a packer fluid for 6 years
• 177ºC, 14,000 psi
• S13Cr tubing failed from
CaCl2 packer fluid
• Well worked over and re-completed
with Cs formate
• 1.4 g/cm3 Na/K formate used
as packer fluid
• Tubing retrieved 6 years
later
• Tubing was in excellent
condition.
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11. The economic benefits provided by formate
brines in HPHT gas field developments
Formate brines improve the economics of HPHT gas field
developments by :
Reducing well delivery time and costs
Improving operational safety and
reducing risk
Delivering production rates that exceed expectations
Providing more precise reservoir definition
Detailed explanation and evidence later in this presentation
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12. Formate brines used by OMV in Pakistan in
2005-6 for drill-in and completions in HPHT gas wells
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13. Formate brines used by OMV in Pakistan in
2005-6 for drill-in and completion in HPHT gas wells
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15. Useful reference material
The Formate Technical Manual
- 26 chapters
- > 400 pages
- Available in English, Spanish and Chinese
- Updated and expanded every month
Recent SPE papers
SPE 130376 (2010): “A Review of the Impact of the Use of Formate Brines
on the Economics of Deep Gas Field Development Projects”
SPE 145562 (2011): “Life Without Barite: Ten Years of Drilling Deep HPHT
Gas Wells With Cesium Formate Brine”
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16. Another source of formate information
The Formate Brines group on LinkedIn – www.linkedin.com
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17. And another source of formate information....
The Formate Brines newsletter – Issue #9 out this week
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18. Formate brines – Discovery and qualification by
Shell Research
Shell patent the use
of formates as
polymer stabilisers
Shell discover
cesium formate
brine
Shell publish first
SPE papers on
formate brines
1987 1988 1989 1990 1991 1992
Shell R&D in UK study the effect of sodium
and potassium formates on the thermal
stability of drilling polymers
Shell R&D in The Netherlands carry out
qualification work on formate brines as
deep slim-hole (HPHT) drilling fluids
Start of Shell’s deep
slim-hole drilling
R&D programme
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19. Formate Brines – Properties that make them
excellent drilling and completion fluids
• Density up to 2.3 g/cm3 and pH 9-10
• Only monovalent ions (Na+, K+, Cs+, HCOO-)
• Stabilise shales (K, Cs and low water activity)
• Protect polymers at high temperature
• Less corrosive than other brines
• Good lubricity
• Non-toxic and readily biodegradable
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20. Benefits of formate brines – Compatible with
polymers, so can be used as drilling fluids
A traditional low-solids formate drilling fluid formulation
Component Function Concentration
Formate brine
Density
Lubricity
Polymer protection
Biocide
1 bbl
Xanthan
Viscosity
Fluid loss control
0.75 – 1 ppb
Lo- Vis PAC and modified
starch
Fluid loss control 4 ppb each
Sized calcium carbonate Filter cake agent 10 – 15 ppb
K2CO3/KHCO3
Buffer
Acid gas corrosion
control
2 – 8 ppb
This simple formulation has been in field use since 1993 – good to 160o C
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21. Formate brines launched as low-solids drilling
fluids in mid-1990’s
John Downs - Formate Brine Ltd
Property Typical values
pH 9 – 10.5
PV [cP] 15 - 20
YP [lb/100ft2] 8 - 15
10” gel 2 - 5
10’ gel 3 - 6
HPHT fluid loss [mL] < 10
API fluid loss < 3
Service company brand names:
Baker Hughes : CLEAR-DRILL (1994)
M-I : FLOPRO (1995)
Baroid : BRINEDRIL
Filter cake on aloxite disc
21
22. Benefits of formate brines - they raise the
thermal stability ceiling of polymers
Bar graph showing the temperature at which polymers lose 50% of
their viscosity after 16 hours hot rolling
Temperature [deg C]
66 116 166
150 200 250 300 350 400
Temperature [deg F]
Starch
PAC
Xanthan
Potassium formate
(1.59 sg 13.25 ppg)
Sodium formate
(1.32 sg 11.05 ppg)
Potassium chloride
(1.16 sg 9.66 ppg)
Sodium chloride
(1.19 sg 9.91 ppg)
Sodium bromide
(1.53 sg 12.75 ppg)
Calcium chloride
(1.39 sg 11.58 ppg)
Freshwater
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23. Benefits of formate brines - ROP enhancement
Low-solids formate brines increase drilling ROP by >100%
compared to OBM (in carbonates and shale)
Effect of Mud on Rate of Penetration
Carthage Marble with 7 Blade PDC Bit
50
40
30
20
10
0
Water
16ppg OBM
16ppg CsFm
16ppg OBM + Mn
0 5,000 10,000 15,000 20,000 25,000 30,000
Weight on Bit (lbf)
Rate of Penetration (ft/hr)
Data from DOE Deep Trek project , see SPE paper 112731
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24. Benefits of formate brines - ROP enhancement
Zero-solids formate brines can increase drilling ROP by 200-300% vs
WBM
Zero-solids potassium formate brines are now breaking records as
drilling fluids in the Montney and Duvernay shales in Canada
Data from SPE paper 36425 (1996)
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25. Benefits of formate brines - ROP enhancement
Ramsey et al found correlation between Fann 600 reading of drilling
fluids and ROP in sandstone
Note the effect of the calcium carbonate (solids) concentration on
Fann 600 reading and ROP with formate brine
Data from SPE paper 36396 (1996)
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26. Benefits of formate brines – Zero/low solids
gives better hydraulics
• Lower Surge and Swab Pressures
- Faster tripping times
- Reduced risk of hole instability
or well control incidents
• Lower System Pressure Losses
- More power to motor
• Lower ECD
- Drill in narrower window between pore
and fracture pressure gradients
- Less chance of fracturing well
and causing lost circulation
• Higher Annular Flow Rates
- Better hole cleaning
John 26 Downs - Formate Brine Ltd
27. Benefits of formate brines – Natural lubricity
Steel-steel coefficient of friction in potassium formate brine (BP test)
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28. Benefits of formate brines – Low methane
solubility
• Low methane solubility and diffusion rates
- Easier kick detection
- Low rate of static influx
• Mud properties not degraded by gas influx
Fluid Solubility (kg/m3)
Diffusion coefficient
(m2/sec x 108)
Diffusion flux
(kg/m2s x 106)
OBM 164 1.15 53.30
WBM 5 2.92 3.98
Formate brine 1 0.80 0.25
Solubility of methane in drilling fluids: T = 300°F (149°C), P = 10,000 psi (690 bar)
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29. Finnish Environment Institute recommends the use of
potassium formate in sensitive groundwater areas
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30. Extracts from summary of Finnish Environment
Institute report on potassium formate
“Potassium formate is already widely used in Finnish airports. According to a
recently completed follow-up study conducted over several years, formate
biodegrades rapidly in the ground, even at low temperatures. This prevents its
infiltration into groundwater”
“In Finland, potassium formate is currently the sole de-icing agent used on
nine roads crossing valuable groundwater areas…. For the follow-up study,
data on groundwater quality was collected from three of the groundwater
areas. No negative impacts were observed on groundwater quality, due to
the use of potassium formate, at any of the three areas in question”
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31. Extracts from abstracts of Finnish Environment
Institute reports on potassium formate
Alternative deicing agents and ground water protection. Final report of MIDAS2-
project (published 2010)
This report summarizes….. novel data from a 7-year follow-up study on the ground water
quality at three areas (Kauriansalmi, Taavetti, and Jaamankangas aquifers) where
potassium formate has been used as a sole de-icing chemical.
On highway 13, running along Kauriansalmi aquifer (Suomenniemi municipality),
potassium formate was used as a sole de-icer from 2002 until the end of 2009. During that
period, no formate was found in the ground water at the area. The average chloride
concentration in the formation has decreased on average by 3,3 % a year since sodium
chloride application came to an end in 2002.
At Taavetti municipal water intake, chloride concentration decreased sharply after 2004
when potassium formate was introduced in de-icing at the area.
This study shows that potassium formate can be applied in winter road maintenance in
particular at sensitive ground water areas, and at airports to minimize the adverse impacts
on ground and surface water resulting from de-icing.
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32. Formate brines – Production and first field use
- Milestones
First field use of
sodium formate:
Shell drills and
completes first
Draugen oil wells
Start of deep
HPHT gas well
drilling with
formates in
Germany
(Mobil, RWE,
Shell)
Potassium
formate brines
used in USA,
Canada,
Mexico,
Venezuela,
First field use of
potassium formate
(with Micromax) :
Statoil drills and
completes Gullfaks
oil well
First use of
formate brine
as packer fluid:
Shell Dunlin
A-14
1993 1994 1995 1996 1997 1998
Brazil,
Ecuador
Sodium formate powder available. Draugen wells each produce 48,000 bbl oil /day
1994 - Potassium formate brine becomes available from Norsk
Hydro (now Addcon)
1997 - Cesium formate
brine becomes available
from Cabot
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33. Potassium formate brine has been used to drill
deep HPHT gas wells since 1995
First use : ExxonMobil’s Walsrode field, onshore northern Germany
- high-angle deep HPHT slim hole low perm gas wells
TVD : 4,450-5,547 metres
Reservoir: Sandstone 0.1-125 mD
BHST : 157o C
Section length: 345-650 m
Drilling fluid: SG 1.45-1.55 K formate brine
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34. Potassium formate from Addcon used in 15 deep
HPHT gas well constructions in Germany ,1995-99
Fluids service provided by M-I and Baroid
Well Name Application Fluid Type Density s.g. (ppg)
Horizontal
Length(m)
Angle (°) BHST (°F) BHCT (°F) TVD (metres) MD (metres)
Permeability
(mD)
Walsrode Z5 W/C K Formate 1.55 (12.93) 345 26 315 na 4450 - 4632 4815 - 5151 0.1 - 125 mD
Wasrode Z6 W/C K Formate 1.55 (12.93) 420 40 315 na 4450 - 4632 4815 - 5151 0.1 - 125 mD
Walsrode Z7 Drill-In K Formate 1.53 (12.77) 690 59 315 295 4541 - 4777 5136 - 5547 0.1 - 125 mD
Söhlingen Z3A Drill-In Formix 1.38 (11.52) 855 89 300 270 4908 5600 na
Söhlingen Z3a Drill-In Na Formate 1.30 (10.85) 855 89 300 270 4908 5600 na
Volkersen Z3 W/C Formix 1.40 (11.68) 512 52 320 na na na na
Kalle S108 Drill-In Formix 1.45 (12.10) 431 60 220 na 6000-6500 6200-6600 na
Weißenmoor Z1 W/C Formix 1.35 (11.27) 634 31 300 na na na na
Idsingen Z1a Drill-In K Formate 1.55 (12.93) 645 61 321 290 4632 - 4800 5257 - 5821 0.1 - 125 mD
Söhlingen Z12 Drill-In
Na
Formate/Formix
1.35 (11.27) 452 28 313 285 4736 - 4937 4846 - 5166 1.0 - 75 mD
Simonswolde Z1 Drill-In K Formate/Formix 1.52 (12.68) 567 35 293 275 4267 - 4572 4236 - 4648 0.1 - 25 mD
Walsrode NZ1 Drill-In Formix 1.51 (12.60) 460 34 290 265 4632 - 4815 4541 - 4693 0.1 - 125 mD
Idzingen Z2 W/C Formix 1.40 (11.68) na na 320 na 4632 - 4800 5257 - 5821 0.1 - 125 mD
Voelkersen NZ2 W/C Formix 1.40 (11.680 na na 320 na na na na
Söhlingen Z13 Drill-In/Frac K Formate/Formix 1.30 (-1.56)(10.85) 1200 90 300 285 4724 5486 - 6400 0,1 - 150 mD
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35. Summary of potassium formate brine use in
HPHT gas wells in Germany,1995-99
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36. Addcon’s potassium formate plant in Norway has
been supplying the oil industry since 1994
Production Site
ADDCON NORDIC AS
Storage tanks for raw
materials
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37. Potassium formate production by Addcon
• The first and largest producer of potassium formate
- Brine production capacity : 800,000 bbl/year
- Non-caking powder capacity: 8,400 MT/year
• Direct production from HCOOH and KOH
• High purity product
• Large stocks on quayside location
• Fast service – by truck, rail and sea
• Supplier to the oil industry since 1994
50 % KOH
4,500 m3
6,300 MT
94 %
Formic acid
5,000 m3
Feedstock storage tanks in
Norway
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38. Addcon’s new potassium formate plant in
Bitterfeld, Germany
Only 7 hours drive from Bitterfeld to Vienna area
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40. Typical potassium brine grades
% w/w Density TCT*
SG oC
75 1.57 7
71 1.53 2
63 1.46 -13
* Crystals of potassium formate
added to encourage crystallisation
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41. Formate brines – Some important milestones :
1999-2004
First
production of
non-caking
crystalline K
formate by
Addcon
First drilling
jobs with
K/Cs formate
brine:
Huldra and
Devenick
HPHT
First use of
Cs-weighted
LSOBM as
perforating
completion
fluid
(Visund)
1999 2000 2001 2002 2003 2004
First of 14
Kvitebjørn
HPHT wells
drilled and
completed
with K/Cs
formate
brines
Formate brines used as packer fluids for HPHT wells in GOM.
First well : ExxonMobil’s MO 822#7 (215oC BHST) in 2001
Use of Cs-weighted oil-based completion fluids for
oil reservoirs : Visund, Statfjord, Njord, Gullfaks,
Snorre , Oseberg, Rimfaks 2001 – present
First use of
K/Cs formate
brine :
Completion
job in
Shearwater
well (Shell
UK)
Cs-weighted
LSOBM used
as OH screen
completion
fluid
(Statfjord)
First use of
K/Cs
formate
brine as
HPHT well
suspension
fluid
(Elgin)
Individual Draugen oil wells (1993) and Visund oil wells (2003) have similar
flow rates of around 50,000 bbl oil/day
41 John Downs - Formate Brine Ltd
42. Cesium formate produced by Cabot in Canada
from pollucite ore
Pollucite ore
Cs0.7Na0.2Rb0.04Al0.9Si2.1O6·(H20)
• Mined at Bernic Lake, Manitoba
• Processed on site to Cs formate brine
• Cs formate brine production 700 bbl/month
• Cs formate stock built up to 30,000 bbl
42 John Downs - Formate Brine Ltd
43. The first sustained use of K/Cs formate brine was in
the world’s largest HPHT gas field development
Elgin/Franklin field – UK North Sea
Cesium formate brine used by TOTAL in 34 well
construction operations in 8 deep gas fields in
period 1999-2010
43 John Downs - Formate Brine Ltd
44. Formate brines – Some published milestones
2005 -2010
OMV
Pakistan
start using K
formate to
drill and
complete
(with ESS) in
HPHT gas
wells
Saudi Aramco
start using K
formate to drill
and complete
(with ESS) in
HPHT gas
wells
Gravel pack
with K
formate
brine in
Statfjord B
First MPD
operation in
Kvitebjørn
with K/Cs
formate
“designer
fluid”
First of 12
completions
in the
Kashagan
field with
K/Cs formate
Petrobras
use K
formate
brine for
open hole
gravel packs
in Manati
field
2005 2006 2007 2008 2009 2010
Total’s West
Franklin F9
well (204oC)
perforated in
K/Cs formate
brine
K/Cs formate brines used as well perforating fluids in 11 HPHT gas fields in UK North Sea : Dunbar,
Shearwater, Elgin, Devenick , Braemar , Rhum, Judy , Glenelg , Kessog , Jura and West Franklin
1999-2011
44 John Downs - Formate Brine Ltd
45. Saudi Aramco have been drilling HPHT gas wells
with potassium formate brine since 2003
45 John Downs - Formate Brine Ltd
46. Saudi Aramco use of formate brines, 2003-2009
• 7 deep gas fields
• 44 HPHT wells drilled
• 70,000 ft of reservoir
drilled at high angle
• 90,000 bbl of brine
recovered and re-used
• Good synergy with ESS,
also OHMS fracturing
46 John Downs - Formate Brine Ltd
47. Summary from Aramco’s OTC paper 19801
Aramco consume around 300 m3/month of K formate brine
47 John Downs - Formate Brine Ltd
48. Potassium formate brine weighted with Micromax®
in Kuwait and Saudi Arabia
Good results in first 9 HPHT wells –
could become the standard HPHT
fluid for KOC
SPE 132151 (2010) “Successful HPHT Application of Potassium
Formate/Manganese Tetra-Oxide Fluid Helps Improve Drilling
Characteristics and Imaging Log Quality”
SPE/IADC 147983 (2011) “Utilization of Non-damaging Drilling Fluid
Composed of Potassium Formate Brine and Manganese Tetra Oxide to
Drill Sandstone Formation in Tight Gas Reservoir
SPE 163301 (2012) “Paradigm Shift in Reducing Formation Damage:
Application of Potassium Formate Water Based Mud in Deep HPHT
Exploratory Well”
48 John Downs - Formate Brine Ltd
49. Potassium formate brine weighted with Micromax for
drilling deep HPHT fractured carbonate wells
10,000 psi, 140oC, H2S = 4-12%, CO2 = 1-6%
49 John Downs - Formate Brine Ltd
50. Potassium formate brine weighted with Micromax for
drilling deep HPHT fractured carbonate wells
“The results were extraordinary when compared to wells
drilled with ..OBM” – Production rates x 3 higher
50 John Downs - Formate Brine Ltd
51. Pakistan - OMV use potassium formate brine for
HPHT deep gas well drilling and completions
51 John Downs - Formate Brine Ltd
52. Extracts from OMV’s SPE papers and SPE
presentations – note 1,700 psi overbalance, and 350oF
52 John Downs - Formate Brine Ltd
53. OMV drills and completes using ESS in
potassium formate brine – Pakistan, 2006/7
53 John Downs - Formate Brine Ltd
54. Norway, 2002 - Perforating in solids-free oil-based
kill pill weighted with formate brine
• Visund field
- BHST: 118o C
- Fluid density: SG 1.65
- 13 wells – 1000- 2000 metre horizontal sections
- Drilled with OBM ,completed with perforated liners
• Justification for use:
- First 3 wells badly damaged by CaBr2 kill pill
- PI only 60-90 m3/bar/day
54 John Downs - Formate Brine Ltd
55. Perforating Visund wells in solids-free oil-based
kill pill weighted with formate brine
• Visund – Change to formate kill
pill (see SPE 73709, 58758 and 84910)
- Next 3 wells perforated in formate fluid
-Also used new perforating guns, in dynamic
underbalance
• Results :
- Eliminated formation damage problem
- PI increased up to 900 m3/bar/day
- 300-600% PI improvement
- Best well : 53,000 bbl/day
Visund well productivity
60 70 50
220
620
900
1000
900
800
700
600
500
400
300
200
100
0
Well
m3 oil/bar/day
Formate brine
Bromide brine
55 John Downs - Formate Brine Ltd
56. Formate brines used as HPHT cased well
completion fluids after drilling with OBM
Formate brines have been used as (perforating) completion fluids
for cased wells in 9 HPHT gas fields in the North Sea
• Shearwater
• Elgin/Franklin
• Braemar
• Rhum
• Judy
• Glenelg
• Kessog
• Jura
• West Franklin
56 John Downs - Formate Brine Ltd
57. Managed Pressure Drilling and completion of
fractured carbonates with formate brine
SPE 165761 (2012) “ Experience with Formate Fluids for Managed Pressure
Drilling and Completion of Sub-Sea Carbonate Gas Development Wells”
• Petronas - Kanowit field – 2 sub-sea gas wells
• Managed Pressure Drilling in fractured carbonate
with K formate brine improved economics by:
- Minimising fluid losses
- Reducing fluid cost (by using K formate)
- Improving production by 50%
- Eliminating need for stimulation (no acidising)
57 John Downs - Formate Brine Ltd
58. Kanowit SS-1 : Production profile from start-up - natural clean-up
– no stimulation . Carbonate reservoir
• 100 MMscfd gas and 4,000 bpd condensate after 5 hours
• >150 MMscfd gas and > 6,000 bpd condensate after 9 hours
59. Kanowit SS-1 : Multi-rate well test results from carbonate
Both wells can produce > 150 MMscfd gas and > 6,000 bpd condensate
MRT measurements on well SS-1 before acidizing (Mahadi et al, 2013)
MRT Test
Choke size
(/64)
Well Head
Pressure
(psi)
Gas Flow rate
Choke correlation
(MMscfd)
Gas Flow rate
Sonar
(MMscfd)
PDG Pressure
(psi)
PDG Temp
(oF)
1 112 2874.4 159.16 147.61 3857.0 252
2 88 3273.0 111.85 108.76 3932.2 252
3 64 3476.8 63.46 64.51 3978.5 251.7
4 40 3560.5 25.84 28.01 3998.8 250.1
The maximum potential flow rate figures are 50% higher than the technical
potential predicted in the original field development plan.
60. North Sea - Formate brines used as combined
HPHT drill-in and completion fluids
33 development* wells drilled and completed in 7 HPHT offshore
gas fields
• Huldra (6 )
• Tune (4)
• Devenick (2)
• Kvitebjoern (8 O/B and 5 MPD)
• Valemon (1)
• Kristin (2) – Drilled only
• Vega (5)
* Except Valemon (appraisal well)
Mostly open hole stand-alone sand screen completions
60 John Downs - Formate Brine Ltd
61. Tune field – HP/HT gas condensate reservoir drilled
and completed with K formate brine, 2002
4 wells : 350-900 m horizontal reservoir sections. Open hole screen
completions. Suspended for 6-12 months in formate brine after completion
61 John Downs - Formate Brine Ltd
62. Tune wells - Initial Clean-up – Operator’s view
(direct copy of slide) June 2003
• Wells left for 6-12 months before clean-up
• Clean-up : 10 - 24 hours per well
• Well performance
• Qgas 1.2 – 3.6 MSm3/d
• PI 35 – 200 kSm3/d/bar
• Well length sensitive
• No indication of formation damage
Well length [m MD]
• Match to ideal well flow simulations (Prosper) - no skin
• Indications of successful clean-up
• Shut-in pressures
• Water samples during clean-up
• Formate and CaCO3 particles
• Registered high-density liquid in separator
• Tracer results
Before After
• A-12 T2H non detectable
• A-13 H tracer indicating flow from lower reservoir first detected 5 sd after
initial clean-up <-> doubled well productivity compared to initial flow data
• No processing problems Oseberg Field Center
SIWHP SIDHP SIWHP SIDHP
bara bara bara bara
A-11 AH 169 - 388 -
A-12 T2H 175 487 414 510
A-13 H 395 514 412 512
A-14 H 192 492 406 509
3350
3400
3450
3500
3550
3600
0 100 200 300 400 500 600 700 800 900 1000
Depth [m TVD MSL]
A-11AH
A-12HT2
A-13H
A-14H
A-11 AH plugged back
62 John Downs - Formate Brine Ltd
63. Tune – Production of recoverable gas and condensate
reserves since 2003 (NPD data)
Good early production from the 4 wells
- No skin (no damage)
- 12.4 million m3 gas /day
- 23,000 bbl/day condensate
Good sustained production
- 90% of recoverable hydrocarbon
reserves produced by end of Year 7
NPD current estimate of RR:
- 18.3 billion m3 gas
- 3.3 million bbl condensate
Rapid and efficient drainage of the reservoir
63 John Downs - Formate Brine Ltd
64. Huldra field – HPHT gas condensate reservoir
drilled and completed with formate brine, 2001
• 6 production wells
• 1-2 Darcy sandstone
• BHST: 147oC
• TVD : 3,900 m
• Hole angle : 45-55o
• Fluid density: SG1.89-1.96
• 230-343 m x 81/2” reservoir sections
• Open hole completions, 65/8” wire wrapped
screens
• Lower completion in formate drilling fluid and
upper completions in clear brine
John 64 Downs - Formate Brine Ltd
65. Comments from Huldra project manager
65
TROND JUSTAD
Manager-Huldra Project
Bergen, Norway
“CESIUM FORMATE HAS PLAYED A KEY ROLE in the development of the Huldra field (a high-temperature,
high-pressure gas field being developed by Statoil in the North Sea). Without it Statoil
could not have developed the field without major consequences on our plans, including the very
expensive redesign of all wells. The need to use a cesium formate-based drilling fluid became clear
after we experienced severe operational limitations when we drilled the first reservoir section with a
different product. Also, quite early in the process, we found that good synergies could be achieved
when using the same fluid for the drilling and completion phases.
“Cesium formate has significantly improved the safety and well control aspects of the project. It has
demonstrated good drillability with good hole cleaning, faster tripping speeds and absolutely no sag.
During flow checks, the fluid is completely stable after only 20 minutes, compared to 45 to 60 minutes
when using another product. This results in significant savings on every trip, as several flow checks
must be done each time the drill string is run in and out of a high-temperature, high-pressure well.
“For the specific conditions of the Huldra field, there is no realistic fluid alternative for successfully
drilling and completing the wells” - TROND JUSTAD
John Downs - Formate Brine Ltd
66. Huldra – Production of recoverable gas and
condensate reserves since Nov 2001 (NPD data)
Plateau production from first 3 wells
- 10 million m3 gas /day
- 30,000 bbl/day condensate
Good sustained production
- 78% of recoverable gas and 89% of
condensate produced by end of Year 7
- Despite rapid pressure decline.....
NPD current estimate of RR:
- 17.5 billion m3 gas
- 5.1 million bbl condensate
Rapid and efficient drainage of the reservoir
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67. Kvitebjørn field – HPHT gas condensate reservoir drilled
and completed with K/Cs formate brine, 2004-2013
• 13 wells to date – 8 O/B, 5 in MPD mode
• 100 mD sandstone
• BHST: 155oC
• TVD : 4,000 m
• Hole angle : 20-40o
• Fluid density: SG 2.02 for O/B
• 279-583 m x 81/2” reservoir sections
• 6 wells completed in open hole : 300-micron single wire-wrapped
screens.
• Remainder of wells cased and perforated
John 67 Downs - Formate Brine Ltd
68. A few of the highlights from Kvitebjoern
Fast completions and high well productivity
Kvitebjoern
well
Completion
time
(days)
A-4 17.5
A-5 17.8
A-15 14.8
A-10 15.9
A-6 12.7 *
Operator comments after well testing (Q3 2004 )
* Fastest HPHT well completion
in the North Sea
“The target well PI was 51,000 Sm3/day/bar This target
would have had a skin of 7”
“A skin of 0 would have given a PI of 100,000”
“THE WELL A-04 GAVE A PI OF 90,000 Sm3/day/bar
(ANOTHER FANTASTIC PI)”
The Well PI was almost double the target
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69. Kvitebjørn– Production of recoverable gas and
condensate reserves since Oct 2004 (NPD data)
Good production reported from first 7 wells in 2006
- 20 million m3 gas /day
- 48,000 bbl/day condensate
Good sustained production (end Y8)
- 37 billion m3 gas
- 17 million m3 of condensate
- Produced 70% of original est. RR by
end of 8th year
NPD : Est. RR have been upgraded
- 89 billion m3 gas (from 55)
- 27 million m3 condensate (from 22)
Note : Shut down 15 months, Y3-5
- To slow reservoir pressure depletion
- Repairs to export pipeline
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70. Economic benefits of using formate brines
• SPE 130376 (2010): “A Review of the Impact of the Use of Formate Brines
on the Economics of Deep Gas Field Development Projects”
• SPE 145562 (2011): “Life Without Barite: Ten Years of Drilling Deep HPHT
Gas Wells With Cesium Formate Brine”
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71. Economic benefits from using formate brines
- Latest paper
71 John Downs - Formate Brine Ltd
72. Economic benefits from using formate brines
- Good well performance and recovery of reserves
• “High production rates with low skin” *
• “ We selected formate brine to minimise well control problems
and maximise well productivity”*
* Quotes by Statoil relating to Kvitebjoern wells (SPE 105733)
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73. Economic benefits from using formate brines
- More efficient and safer drilling
Better/safer drilling environment saves rig-time costs
• Stable hole: see LWD vs. WL calipers in shale
• Elimination of well control* and stuck pipe
incidents
• Good hydraulics, low ECD
• Good ROP in hard abrasive rocks
* See next slide for details
“ a remarkable record of zero well control incidents in all 15
HPHT drilling operations and 20 HPHT completion operations”
73 John Downs - Formate Brine Ltd
74. Formate Brines : Allow fast solids-free drilling
Solids-free formate brines drill deep horizontal well sections much
faster than muds like OBM – and cause less formation damage
74 John Downs - Formate Brine Ltd
75. Economic benefits from using formate brines
- Improved well control and safety
• Elimination of barite and its sagging problems
• Elimination of oil-based fluids and their gas solubility problem
• Low solids brine Low ECD (SG 0.04-0.06) and swab pressures
• Inhibition of hydrates
• Ready/rapid surface detection of well influx
• Elimination of hazardous zinc bromide brine
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76. Economic benefits from using formate brines
- More efficient/faster completions
- Drill-in and completing with
formate brine allows open hole
completion with screens
- Clean well bores mean no tool/seal
failures or blocked screens
- Completion time 50% lower than
wells drilled with OBM
“ fastest HPHT completion operation ever performed in North Sea (12.7 days)”
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77. Economic benefits from using formate brines
• No differential sticking
• Pipe and casing running speeds are fast
• Mud conditioning and flow-check times are short
• Displacements simplified, sometimes eliminated
Flow check fingerprint
for a Huldra well
Duration of
flow back
(minutes)
Fluid Gain
(bbl)
30 0.8
15 0.56
20 0.44
30 0.56
- Operational efficiencies
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78. Economic benefits from using formate brines
- Good reservoir definition if Cs present in fluid
• High density filtrate and no barite
• Filtrate Pe up to 259 barns/electron
• Unique Cs feature - makes filtrate invasion
highly visible against formation Pe of 2-3 b/e
• LWD can “see” the filtrate moving (e.g. see
the resistivity log on far right – drill vs ream
• Good for defining permeable sands (see
SAND-Flag on log right )
• Consistent and reliable net reservoir definition
from LWD and wireline
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79. Economic benefits from using formate brines
- Good reservoir imaging
• Highly conductive fluid
• Clear resistivity images
• Information provided:
- structural dip
- depositional environment
- geological correlations
79 John Downs - Formate Brine Ltd
80. Formate brines – Summary of economic
benefits provided to users
Formate brines improve oil and gas field development
economics by :
Reducing well delivery time and costs
Improving well/operational safety and reducing risk
Maximising well performance
Providing more precise reservoir definition
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81. Formate brines enable open-hole screen
completions in high-angle HPHT wells
Formate brines are low-solids drill-in and completion fluid systems
that provide massive benefits in open-hole screen completions in HPHT
wells
• Generally non-damaging to reservoir and screens
• Clean-up naturally during start-up (10-20 hours)
• Low skins
• No well stimulation required
• Good with expandable screens (Saudi, Pakistan)
Formates are perhaps the only high-density fluids that routinely deliver
unimpaired open hole screen completions in HPHT wells
John Downs - Formate Brine Ltd
82. Finnish Environment Institute recommends the use of
potassium formate in sensitive groundwater areas
Environ Sci Technol. 2005 Jul 1;39(13):5095-100.
Use of potassium formate in road winter deicing can reduce groundwater deterioration.
Hellstén PP1, Salminen JM, Jørgensen KS, Nystén TH.
“Potassium formate was used to de-ice a stretch of a highway in Finland. The fate of
the formate was examined by monitoring the groundwater chemistry in the
underlying aquifer of which a conceptual model was constructed. In addition, we
determined aerobic and anaerobic biodegradation rates of formate at low
temperatures (-2 to +6 degrees C) in soil microcosms.
Our results show that the formate did not enter the saturated zone through the thin
vadose zone; thus, no undesirable changes in the groundwater chemistry were
observed. We recorded mineralization potential up to 97% and up to 17% within 24 h
under aerobic and anaerobic conditions, respectively, in the soil and subsurface
samples obtained from the site. This demonstrates that biodegradation in the topsoil
layers was responsible for the removal of the formate.
We conclude that the use of potassium formate can potentially help diminish the
negative impacts of road winter deicing on groundwater without jeopardizing traffic
safety.”
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