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
88. june 9 heater test modeling highlights rutqvistleann_mays
This document summarizes modeling work done as part of the DECOVALEX-2015 international modeling collaboration on heater experiments. It describes two heater experiments, one in Opalinus clay at the Mont Terri rock laboratory and one in siliceous mudstone at the Horonobe underground research laboratory. International modeling teams developed models of both experiments to predict thermal-hydrological-mechanical behavior during heating. The models generally captured trends like heating and drying near the heat source, with some variations. Comparisons of predictions to experimental measurements showed good agreement for temperature but smaller than predicted stresses. The collaboration provided an opportunity for model testing and development.
This document summarizes a reservoir simulation study comparing waterflood modeling using Excel and Eclipse reservoir simulators. Excel was used to model a reservoir as a series of tubular flow paths, with equations to calculate injection rates, pressures, and recoveries for each tube over time. Eclipse simulated the full 3D reservoir. Results for the first layer were similar between the simulators for breakthrough time (5.48% error) and cumulative oil (9.76% error). However, the economic limit time differed more (26.09% error). While Excel provides a conceptual approach, Eclipse is preferred for its ability to directly model complex multi-layer reservoirs without manual calculations.
Moffett RAB: Petroleum Program Update, November 13, 2008Steve Williams
The document provides an update on the petroleum program at the former Naval Air Station Moffett Field. It discusses background information, completed closure activities for various petroleum tanks and pipelines based on soil and groundwater sampling results. Current projects presented include draft investigation reports for the former aircraft wash rack, Site 5 channel deposit, and Building 29 and 55 pipelines. Upcoming work includes further sampling and characterization of sites such as Site 20, the former Navy Exchange gas station, and various aboveground storage tanks. The overall goal of the petroleum program is to investigate and obtain closure for petroleum sites at the former base.
The document discusses challenges with using tracer technology to study heavy oil reservoirs. It provides an overview of tracer types including passive tracers that follow fluid phases and active tracers that interact with the system. Challenges are presented for tracer use in heavy oil recovery methods like CSS, THAI, SAGD and VAPEX. New tracer types are needed that can withstand high temperatures and be stable against biodegradation.
Team M Reservoir simulation-an extract from original pptMukesh Mathew
This document summarizes reservoir simulation work for an oil field. Static and dynamic reservoir models were created using well logs, core data, and production data. Multiple development scenarios were simulated including natural depletion, water flooding, gas injection, and EOR methods. The optimum scenario involved 13 producer wells and 8 water injector wells, achieving a recovery factor of 55% over 25 years. Alternate scenarios like gas injection and polymer flooding were also considered.
This document provides an overview of the STARS reservoir simulation software from CMG. STARS can accurately model various thermal and enhanced oil recovery processes at multiple scales from core floods to field-scale. It allows users to optimize field development plans, model complex wellbore designs, simulate formation of emulsions and foams, and predict asphaltene precipitation. STARS remains the industry standard for simulating thermal recovery processes like SAGD and steamflooding as well as chemical EOR processes through its robust reaction kinetics and ability to mechanistically model physical processes.
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.
The document discusses oil recovery methods including primary, secondary, and tertiary (enhanced oil recovery) techniques. Primary recovery uses natural reservoir pressures to produce 10-25% of oil initially in place. Secondary recovery maintains pressure through water or gas flooding to produce additional oil. Tertiary/enhanced oil recovery (EOR) uses sophisticated thermal or non-thermal methods like gas injection to extract more oil, becoming more important as oil prices rise. The document focuses on different driving mechanisms in primary recovery and introduces EOR methods.
The document discusses water shut-off methods for depleted oil and gas wells using polymer injection techniques. It provides details on the impacts of water production on wells, including more complex separation and rapid corrosion. Main causes of water production are discussed, along with well-known shut-off techniques like polymer and gel injection. The benefits of the company's proprietary water shut-off technology using polymer composites are summarized, including increased oil recovery rates up to 80-140% compared to standard extraction methods. Application experience is provided on wells up to 6,000m deep and 190°C, decreasing water cuts by 75-95%.
This document provides an overview of enhanced oil recovery (EOR) methods using gas injection. It discusses the main gas injection methods including miscible and immiscible processes. Key injection gases are carbon dioxide (CO2), nitrogen (N2), and natural gas. CO2 flooding has been widely used in the US and offers potential for combining EOR with CO2 storage. Economics of CO2-EOR and carbon capture and storage (CCS) are also reviewed. While gas injection is common, the number of N2 flood projects has declined with most current EOR relying on natural gas or CO2 if it is available. Offshore, EOR potential exists but is currently limited to gas and water-alternating-
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
CONING CONTROL AND RECOVERY IMPROVEMENT IN BOTTOM WATERMOHD RUZAINI RUSLI
This document discusses techniques for improving oil recovery and reducing water production in reservoirs with bottom water drives that are prone to water coning. It analyzes the performance of conventional, downhole water sink (DWS), and downhole water loop (DWL) well completions using reservoir modeling. The modeling shows that DWS wells produced the most oil at 2.48 million barrels, while DWL wells produced slightly less at 1.81 million barrels but reinjected produced water back into the reservoir. Initial reservoir pressure and perforation interval length had little effect on oil recovery. The conclusion is that DWL wells are preferable to conventional wells as they produce less water by reinjecting it, controlling water coning and preventing rapid pressure depletion
Increasing interest by governments worldwide on reducing CO2 released into the atmosphere form a nexus of of opportunity with enhanced oil recovery which could benefit mature oil fields in nearly every country. Overall approximately two-thirds of original oil in place (OOIP) in mature conventional oil fields remains after primary or primary/secondary recovery efforts have taken place. CO2 enhanced oil recovery (CO2 EOR) has an excellent record of revitalizing these mature plays and can dramatically increase ultimate recovery. Since the first CO2 EOR project was initiated in 1972, more than 154 additional projects have been put into operation around the world and about two-thirds are located in the Permian basin and Gulf coast regions of the United States. While these regions have favorable geologic and reservoir conditions for CO2 EOR, they are also located near large natural sources of CO2.
In recent years an increasing number of projects have been developed in areas without natural supplies, and have instead utilized captured CO2 from a variety of anthropogenic sources including gas processing plants, ethanol plants, cement plants, and fertilizer plants. Today approximately 36% of active CO2 EOR projects utilize gas that would otherwise be vented to the atmosphere. Interest world-wide has increased, including projects in Canada, Brazil, Norway, Turkey, Trinidad, and more recently, and perhaps most significantly, in Saudi Arabia and Qatar. About 80% of all energy used in the world comes from fossil fuels, and many industrial and manufacturing processes generate CO2 that can be captured and used for EOR. In this 30 minute presentation a brief history of CO2 EOR is provided, implications for utilizing captured carbon are discussed, and a demonstration project is introduced with an overview of characterization, modeling, simulation, and monitoring actvities taking place during injection of more than a million metric tons (~19 Bcf) of anthropogenic CO2 into a mature waterflood.
Longer versions of the presentation can be requested and can cover details of geologic and seimic characterization, simulation studies, time-lapse monitoring, tracer studies, or other CO2 monitoring technologies.
Overview of Reservoir Simulation by Prem Dayal Saini
Reservoir simulation is the study of how fluids flow in a hydrocarbon reservoir when put under production conditions. The purpose is usually to predict the behavior of a reservoir to different production scenarios, or to increase the understanding of its geological properties by comparing known behavior to a simulation using different geological representations.
CatFT(r) Fischer-Tropsch Process presentationThomas Holcombe
The document describes a new Fischer-Tropsch process called CatFT that addresses previous challenges. It involves coating catalyst onto thin fins for tight temperature control and scalability. Pilot testing showed promising results with high catalyst productivity. Estimates indicate a 100 BPD CatFT plant could be profitable with an IRR over 30% due to lower capital costs compared to conventional designs. The novel design offers advantages for small-scale applications.
This document provides information about cesium formate brine, including its uses, benefits, and the company that produces it. Specifically:
- Cesium formate brine is a high-density, non-toxic brine used for drilling, completing, and suspending deep gas wells. It can have densities up to 143 pcf.
- Using cesium formate brine improves economics by allowing faster drilling and completions while improving well safety. It also maximizes reservoir production and definition.
- Cabot Corporation produces cesium formate brine from pollucite ore in Canada. It has been used in over 250 deep gas wells worldwide since 1999.
This document provides information on estimating oil and gas reserves. It defines various classifications of reserves from proven to unproven, and how reserves are estimated using volumetric, material balance, and production performance methods. The key classifications discussed are proven and probable reserves, with proven reserves having a 90% certainty of recovery and probable having 50% certainty. Volumetric estimation calculates initial hydrocarbon volumes using parameters like rock volume, porosity, fluid properties, and recovery factors.
The document discusses the process for evaluating, implementing, and assessing EOR (Enhanced Oil Recovery) projects. It outlines the key steps as: 1) conducting a feasibility study including screening potential EOR methods and economic evaluation; 2) implementing a trial or pilot project with proposal, preparation, execution, monitoring, and evaluation phases; and 3) reporting the results of the trial or pilot project. The goal is to fully understand the field, identify an economically viable EOR method, test it at a small scale, and assess the results to inform a potential full-scale EOR project.
The document describes a reservoir simulation project involving history matching of an oil reservoir with multiple producers and injectors. 10 different simulation trials were run to match historical production data from 4 key wells by adjusting transmissibility multipliers in different regions of the reservoir model. The best results were achieved in trial 6, where transmissibility was increased in two areas and changed near the main injectors, successfully matching the production of the most important well while having limited effect on other wells. However, fully history matching all 4 wells proved challenging.
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.
The 3S technology combines the simplicity of J-T valves with the effectiveness of turbo-expanders, allowing for natural gas dewpointing without these components. It uses a swirling device, sub/supersonic nozzle, and diffusers to separate gas and liquid phases. The 3S separator has been implemented in various Russian and Chinese gas fields since the 2000s. It offers advantages of low maintenance, capital and operating costs compared to other technologies. Future applications may include subsea gas separation and removal of acid gases.
This document discusses recent trends and the future of ultra deepwater oil field developments. It summarizes that developments in ultra deepwater have very high costs, prompting companies to consider more standardized and innovative solutions. Subsea wells and FPSOs have become the standard for field development below depths of around 2500-3000 meters. New technologies like subsea separation, direct electrical heating of flowlines, and subsea power distribution are being successfully implemented and will likely become more common. Future field developments are expected to utilize more standardized components coupled with innovative technologies to reduce costs and maximize recovery in ultra deepwater environments over the next 5-10 years.
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.
This document discusses the various uses of industrial gases, particularly liquid nitrogen, in the offshore oil and gas industry. It provides an overview of downhole and topside applications of gases, focusing on nitrogen/helium leak testing which is a large market. The document discusses offshore equipment for transporting, storing, and vaporizing cryogenic liquids as well as typical gas consumption amounts. It analyzes the growth potential in areas like Qatar, UAE, and India as offshore natural gas developments increase.
Breaking Paradigms in old Fields. Finding “the reservoir key” for Mature Fiel...Juan Diego Suarez Fromm
Two field examples will be presented, where after 50 years of development; fresh oil and gas were produced by changing some reservoir paradigms.
Upsides could be overlooked due to paradigms on field development. The successful one in terms of reserves and cost effective capital expenditure could be visualized as “finding the key for the field”. But as development takes place over many years (decades), the “key” should be a dynamic concept over time, correlated with technology availability, enabling us a better understanding of petroleum resources size, quality and distribution.
1) Statoil uses an extensive "toolbox" of improved oil recovery (IOR) techniques like water and gas injection, chemicals, and new well technologies to increase oil recovery from fields.
2) One promising new technology is through-tubing drilling and completion, which allows drilling and lining of wellbores simultaneously to improve efficiency and reduce costs.
3) Statoil is developing technologies like steerable drilling liners to further improve through-tubing operations and aims to enable "one-trip" drilling and cementing in the future to maximize oil recovery.
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 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.
Farhad Orak presented research on optimizing production from a field in South Pars gas field using nodal analysis and multilateral well design. The field contains four producing gas layers separated by anhydrite layers in a reservoir 400 meters thick. Conventional wells risk water coning issues on the flanks where lower layers are water-filled. The study models a dual opposed multilateral well using nodal analysis, finding production could be optimized to 114 million standard cubic feet per day by increasing tubing size to 6.18 inches, setting wellhead pressure to 2000 psi, assuming 5% water cut and a skin factor of +1. Recommendations include further investigating horizontal branch length and angle to increase reservoir exposure and controlling production
This document discusses combined cycle power plants and heat recovery steam generators (HRSGs). It provides information on:
1) The basic configuration and working of combined cycle power plants which use waste heat from gas turbines to generate steam and power a steam turbine for additional electricity production.
2) The different types of HRSGs including vertical and horizontal designs as well as components like evaporator sections and schematics of single, dual, and triple pressure Rankine cycles.
3) Performance parameters for HRSG modules in a 101MW combined cycle plant and the relationship between HRSG tube count and plant capacity.
ArcelorMittal South Africa (AMSA) is the largest steel producer in Africa, producing 4.8 million tonnes of steel per year through an integrated process. Through working with the Industrial Energy Efficiency Project, AMSA implemented an energy management system and optimized various energy systems, such as compressed air, pumps, fans, and steam. These optimization projects are estimated to save AMSA approximately R105 million per year in electricity and natural gas costs. Pump system optimization assessments alone have identified potential savings of over R36 million at reduced payback periods.
The document summarizes the installation of an innovative "Capillary Conveyed" gas lift extension system in a well in Vietnam. The existing gas lift system was no longer effective due to declining reservoir pressures. The new system used a 0.75" diameter capillary string to extend the gas lift injection point deeper into the well. After installation, the well resumed production, flowing for 60 days at rates exceeding expectations before being placed on a production cycle. Cumulative production since was 43,000 barrels of oil, with an estimated payback of only 4 days for the installation. The installation demonstrated that the new technology can effectively reinstate production from wells with inefficient gas lift systems.
Gassco - Future Gas Export from the Norwegian Continental Shelf - Thor Otto L...Innovation Norway
This document discusses future gas export from Norway's continental shelf and provides context on the Norwegian gas transportation system. It notes that while production from existing fields is expected to decline after 2020, new discoveries have been made that could extend gas resources. However, developing these new resources located further north will require new gas transportation infrastructure due to the long distances from existing infrastructure. Norway has started evaluating potential transportation solutions through the Barents Sea Gas Infrastructure Forum to enable monetization of gas resources in the Barents Sea.
The document outlines a proposed gas treatment plant with the following key points:
- The plant would process raw shale gas from the Bakken formation to produce compressed natural gas, liquefied natural gas (LNG), and natural gas liquids (NGL) for various uses.
- Major processes would include sour gas treatment to remove hydrogen sulfide, dehydration, demethanization, NGL stabilization, and nitrogen rejection via cryogenic distillation.
- Economics analysis shows total annual revenues of $317 million against operating costs of $395 million, with a total installed capital cost of $144 million.
- Key recommendations are for the plant to move forward given its importance in supplying gas to other
Use of Integrated Modeling on Niger Delta Field - MICHAEL OWARUMEMICHAEL OWARUME
The document discusses using integrated modeling on an onshore Niger Delta oil field to optimize gas condensate well production and forecasting. The methodology developed a combined Prosper and GAP model to represent the vertical lift performance, inflow behavior from well tests, and surface network. History matching validated the model against production rates, pressures, and constraints. Predictions using the integrated model showed flexibility for monthly forecasts within capacity. Recommendations included updating reservoir models, conducting a field survey, integrating compositional modeling, and monitoring test validations for model updates.
1) The document discusses installing an exhaust gas cleaning system called a scrubber on the pilot vessel MV Tarago to comply with sulphur regulations. It will cost $10 million to install and could save $7 million per year in ECA areas by allowing the vessel to continue using cheaper high-sulphur fuel.
2) Key points examined in the pre-study included loss of cargo space, weight and stability impacts, retrofit challenges, power consumption, fresh water usage, and operational impacts. Extensive piping and cabling would be required.
3) Installation of the large scrubber unit, weighing 45 tons, is underway on the vessel. Third-party testing and verification will begin
The document discusses the benefits of using internal coatings for offshore gas pipelines. It provides examples of several major pipeline projects, including the Balgzand-Bacton line between the Netherlands and UK, the Dolphin gas pipeline in the Persian Gulf, and the Langeled gas pipeline in the North Sea, that used internal coatings successfully. The coatings provide corrosion protection during storage and commissioning, allow for easier inspection and commissioning of the pipelines, and enable longer pigging distances.
Similar to SPE 165151 - The Long-term Production Performance of Deep HPHT Gas Condensate Fields Developed Using Formate Brines (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.
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 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.
Evolution of iPaaS - simplify IT workloads to provide a unified view of data...Torry Harris
Evolution of iPaaS
Integration is crucial for digital transformation, and iPaaS simplifies IT workloads, providing a unified view of enterprise data and applications.
🔸 Early Days (2000s)
The rise of cloud computing and SaaS set the stage for iPaaS to address integration needs. Key milestones include:
➤ Early reliance on IBM WebSphere and Oracle middleware.
➤ Informatica Cloud launch in 2006.
➤ Boomi's AtomSphere introduction in 2008.
➤ Gartner's term "iPaaS" in 2011.
🔸 Cloud First Approach (2010-2020)
The shift to cloud-based applications accelerated iPaaS adoption. Developments include:
➤ Low-code/no-code iPaaS platforms like SnapLogic.
➤ Integration of on-premise, cloud, and SaaS applications.
➤ Enhanced capabilities such as API management and data governance.
➤ Emphasis on security and compliance with platforms like Jitterbit.
➤ Leveraging AI/ML technologies for integration tasks.
🔸 Challenges and Costs
MuleSoft's survey highlights costly integration failures. Key issues include:
➤ High labor costs for custom integrations.
➤ Complexities in mapping and managing data.
➤ Integration challenges in industries like airlines and healthcare.
➤ Increased costs due to lack of standardization and security breaches.
🔸 Future of iPaaS
iPaaS will continue to evolve with increased sophistication and adaptability. Future trends include:
➤ Wider adoption across industries.
➤ Hybrid integrations connecting diverse environments.
➤ AI and ML for automating tasks.
➤ IoT integrations for better decision-making.
➤ Event-driven architectures for real-time responses.
iPaaS is essential for addressing integration challenges and supporting business innovation, making strategic investment crucial for competitive resilience and growth.
Uncharted Together- Navigating AI's New Frontiers in LibrariesBrian Pichman
Journey into the heart of innovation where the collaborative spirit between information professionals, technologists, and researchers illuminates the path forward through AI's uncharted territories. This opening keynote celebrates the unique potential of special libraries to spearhead AI-driven transformations. Join Brian Pichman as we saddle up to ride into the history of Artificial Intelligence, how its evolved over the years, and how its transforming today's frontiers. We will explore a variety of tools and strategies that leverage AI including some new ideas that may enhance cataloging, unlock personalized user experiences, or pioneer new ways to access specialized research. As with any frontier exploration, we will confront shared ethical challenges and explore how joint efforts can not only navigate but also shape AI's impact on equitable access and information integrity in special libraries. For the remainder of the conference, we will equip you with a "digital compass" where you can submit ideas and thoughts of what you've learned in sessions for a final reveal in the closing keynote.
WhatsApp Spy Online Trackers and Monitoring AppsHackersList
Learn about WhatsApp spy online trackers, parental monitoring tools, and ethical considerations in WhatsApp surveillance. Discover features, methods, and legal implications of monitoring WhatsApp activity.
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
BT & Neo4j: Knowledge Graphs for Critical Enterprise Systems.pptx.pdfNeo4j
Presented at Gartner Data & Analytics, London Maty 2024. BT Group has used the Neo4j Graph Database to enable impressive digital transformation programs over the last 6 years. By re-imagining their operational support systems to adopt self-serve and data lead principles they have substantially reduced the number of applications and complexity of their operations. The result has been a substantial reduction in risk and costs while improving time to value, innovation, and process automation. Join this session to hear their story, the lessons they learned along the way and how their future innovation plans include the exploration of uses of EKG + Generative AI.
Best Practices for Effectively Running dbt in Airflow.pdfTatiana Al-Chueyr
As a popular open-source library for analytics engineering, dbt is often used in combination with Airflow. Orchestrating and executing dbt models as DAGs ensures an additional layer of control over tasks, observability, and provides a reliable, scalable environment to run dbt models.
This webinar will cover a step-by-step guide to Cosmos, an open source package from Astronomer that helps you easily run your dbt Core projects as Airflow DAGs and Task Groups, all with just a few lines of code. We’ll walk through:
- Standard ways of running dbt (and when to utilize other methods)
- How Cosmos can be used to run and visualize your dbt projects in Airflow
- Common challenges and how to address them, including performance, dependency conflicts, and more
- How running dbt projects in Airflow helps with cost optimization
Webinar given on 9 July 2024
Use Cases & Benefits of RPA in Manufacturing in 2024.pptxSynapseIndia
SynapseIndia offers top-tier RPA software for the manufacturing industry, designed to automate workflows, enhance precision, and boost productivity. Experience the benefits of advanced robotic process automation in your manufacturing operations.
For the full video of this presentation, please visit: https://www.edge-ai-vision.com/2024/07/deploying-large-language-models-on-a-raspberry-pi-a-presentation-from-useful-sensors/
Pete Warden, CEO of Useful Sensors, presents the “Deploying Large Language Models on a Raspberry Pi,” tutorial at the May 2024 Embedded Vision Summit.
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SPE 165151 - The Long-term Production Performance of Deep HPHT Gas Condensate Fields Developed Using Formate Brines
1. SPE 165151
Gunnar Olsvik and Siv Howard, Cabot Specialty Fluids
John Downs, Formate Brine Ltd
SPE European Formation Damage conference , Noordwijk, The Netherlands, 5-7 June 2013
The Long-Term Production Performance of
Deep HPHT Gas Condensate Fields
Developed Using Formate Brines
2. Formate brines
SPE European Formation Damage conference, 5-7 June 2013 2
Sodium
formate
Potassium
formate
Cesium
formate
Solubility 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
3. Formate brines for HPHT gas wells
Low-solids heavy fluids for deep HPHT gas well
constructions
• Reservoir drill-in
• Completion
• Workover
• Packer fluids
• Well suspension
• Fracking (OHMS)
Used in hundreds of HPHT wells since 1995, including some of
Europe’s deepest, hottest and highly-pressured gas reservoirs
3SPE European Formation Damage conference, 5-7 June 2013
4. 42 deep HPHT gas fields developed using formate
brines, 1995-2011* (published data)
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
4SPE European Formation Damage conference, 5-7 June 2013
* Now more HPHT fields in Kuwait, India and Malaysia during 2012-2013
5. The economic benefits of using formate brines in
HPHT gas field developments – Reference 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”
SPE European Formation Damage conference, 5-7 June 2013
5
6. Formate brines – The economic benefits
provided in HPHT gas field developments
Formate brines tend to improve oil and gas field development
economics by :
• Reducing well delivery time and costs
- 12 years of use with screens
- Very good with ESS
• Improving well/operational safety
and reducing risk
• Delivering production rates that exceed expectations
• Providing more precise reservoir definition
6SPE European Formation Damage conference, 5-7 June 2013
7. Several highlights from some Kvitebjoern HPHT gas
wells drilled and completed with formates
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 *
* Fastest HPHT well completion
in the North Sea
7
“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)”
Operator quote after well testing (Q3 2004 )
The Well PI was almost double the target
SPE European Formation Damage Conference, 5-7 June 2013
Fast open hole screen completions and high well productivity
8. But productive for how long ?
Objectives of the analysis presented in this paper :
• Map the production profiles of North Sea HPHT fields
where formate brines were the last fluids to contact the
reservoirs in every well
• Compare actual cumulative production over time against
published estimates of recoverable reserves at start-up
• See if the well construction design influences the
production profile (e.g. Cased vs. Open hole completions)
8SPE European Formation Damage conference, 5-7 June 2013
9. Reviewed long-term production from 8 North Sea
HPHT gas condensate fields in 3 categories
9SPE European Formation Damage conference, 5-7 June 2013
Category Fields Reservoir penetration and well completion
1
Tune
Huldra
All production wells drilled and completed in high-
angle open hole with formate brines. Single filtrate
in reservoir.
2 Kvitebjørn
All production wells drilled and completed in high-
angle open- and cased-holes with formate brines.
Multiple filtrate types in reservoir surrounding cased
holes.
3
Braemar
Glenelg
Jura
Rhum
West Franklin
All production wells drilled with oil-based mud, then
completed in cased hole with formate brines as the
perforating fluids (with and without kill pills).
Multiple filtrate types in all wells
Production data obtained from UK DECC and Norwegian NPD websites
10. Tune field – semi-HP/HT gas condensate reservoir
drilled and completed with formate brines, 2002
10
4 wells : 350-900 m horizontal reservoir sections. Open hole screen
completions. Suspended for 6-12 months in formate brine after completion
SPE European Formation Damage conference, 5-7 June 2013
11. Tune wells - Initial Clean-up – Operator’s view
(direct copy of slide) June 2003
SPE European Formation Damage conference, 5-7 June 2013
11
11
• 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
• 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
• 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
Before After
3350
3400
3450
3500
3550
3600
0 100 200 300 400 500 600 700 800 900 1000
Well length [m MD]
Depth[mTVDMSL]
A-11AH
A-12HT2
A-13H
A-14H
A-11 AH plugged back
12. Tune – Production of recoverable gas and condensate
reserves since 2003 (NPD data)
12
Good early production from the 4 wells
- « No skin»
- 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
Open hole screen completions and single filtrate
SPE European Formation Damage conference, 5-7 June 2013
13. • 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
Huldra field – HPHT gas condensate reservoir
drilled and completed with formate brines, 2001
13SPE European Formation Damage conference, 5-7 June 2013
14. Huldra – Production of recoverable gas and
condensate reserves since Nov 2001 (NPD data)
14
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
Open hole screen completions and single filtrate
SPE European Formation Damage conference, 5-7 June 2013
15. • 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
Kvitebjørn field – HPHT gas condensate reservoir drilled
and completed with formate brines, 2004-2013
15SPE European Formation Damage conference, 5-7 June 2013
16. Kvitebjørn– Production of recoverable gas and
condensate reserves since Oct 2004 (NPD data)
16
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
SPE European Formation Damage conference, 5-7 June 2013
17. Formate brines have been used to complete all of
the cased wells in 5 HPHT fields in UK North Sea
All wells drilled with OBM
17SPE European Formation Damage conference, 5-7 June 2013
* The deepest, hottest and highest-pressured fields in UK North Sea
Field
Operator No.
of
wells
Depth
(meters)
Pressure
(bar)
Temp
(oC)
Wellhead Brine
density
(kg/m3)
Braemar Marathon
1
(NP)
4,500 701 136 Sub-sea 1.86
Rhum BP 3 4,750 862 149 Sub-sea 2.19
West Franklin* Total
2
(NP)
7,327 1,154 204 Platform 1.94
Glenelg* Total
1
(NP)
7,385 1,150 200 Platform 1.78
Jura Total 2 3,935 702 127 Sub-sea 2.09
18. Fluid losses from HPHT wells in UK North Sea
perforated in formate brines
18
SPE European Formation Damage conference, 5-7 June 2013
Field Kill Pill Fluid losses during and
after perforating
(m3)
Comment
Braemar – 1 well No 2.3
Re-perforation of 18 year old
appraisal well. Short flow and
then zero losses
Rhum Yes 0.5
Flowed in first few minutes,
then zero losses for 3 days
Glenelg – 1 well No 17.7
2m3 on perforating and then
15.7m3 seepage losses
Jura
Yes –over
perfs
1.46 Flow stopped within 3 hours
West Franklin No 565
F9Y - Pumping brine at intervals
during period 29 June-18th July
to maintain WHP during 2
perforating runs and fishing
19. Braemar field – Production of recoverable gas and
condensate reserves since September 2003 (DECC data)
19
Estimated (2003) recoverable reserves produced in full from
this single well development by Year 9
Estimated recoverable reserves
- 3.28 billion m3 gas
- 1.59 million m3 condensate
Cumulative production @Sep 2012
- 3.4 billion m3 gas
- 1.9 million m3 condensate
SPE European Formation Damage conference, 5-7 June 2013
20. Glenelg – Production of gas and condensate since
March 2006 (DECC data)
20
No published reserves information ? Similar to Braemar ?
Highest temperature and pressure reservoir developed in UK
North Sea (2006), accessed by single extended reach well
Good initial production
Operator statements :
- «30,000 boe/day capability»
- «500,000 m3/year condensate»
Cumulative production @ Feb 2011
- 2.2 billion m3 gas
- 2.13 million m3 condensate
SPE European Formation Damage conference, 5-7 June 2013
21. West Franklin – Production of gas and condensate
from West Franklin/Franklin 2001-11 (DECC data)
21
No published reserves information. Hottest, highest pressure
commercial development in world (2007), accessed by two
extended reach wells, F7z and F9y
Excellent initial production
Operator statements :
- « F9y has 40,000 boe/day capability»
- «one of most productive wells in
N. Sea»
- «2.6 million m3/day of gas from F9y»
West Franklin has sustained
the Franklin field output
- > 2.5 billion m3 gas per year from Y6
onwards
Note : 566 m3 of cesium formate brine was pumped into formation around F9Y
SPE European Formation Damage conference, 5-7 June 2013
22. BP Rhum field – largest undeveloped gas field
in UK in 2005
SPE European Formation Damage conference, 5-7 June 2013 22
45 mD sandstone reservoir
23. Rhum field – Production of recoverable gas reserves:
December 2005- October 2010 (DECC data)
23
After nearly 5 years the 3 Rhum production wells had produced
35% of the estimated recoverable gas reserves
Estimated recoverable reserves
- 23 billion m3 gas
Cumulative production Oct 2010
- 7.9 billion m3 gas
Production suspended since late
2010
- EU sanctions against Iran
SPE European Formation Damage conference, 5-7 June 2013
24. Jura – Production of gas and condensate since May
2008 (DECC data)
24
Estimated (2008) proved and probable reserves of 170 million
boe – no published segmentation by hydrocarbon type
Good initial production from 2 wells
- 1.87 billion m3 gas produced during Y2
Cumulative production @ June 2012
- 6.58 billion m3 gas
- 1.1 million m3 condensate
= 46 million boe in total
= 27% production of est. RR after 4 years
SPE European Formation Damage conference, 5-7 June 2013
25. Conclusions – Cat 1 HPHT wells - Drilled and
completed in high-angle open hole with formate brines
Tune and Huldra fields produced 100% of recoverable gas and
condensate reserves within 10 years – average 3.5 billion m3
gas /well
Gas – 90% in 7-8 years Condensate – 90% in 5-7 years
Provides evidence that drilling and completing HPHT gas production wells in
open hole with formate brines can be a successful strategy
25Formate Brine Seminar - Stavanger, 22 November 2012
26. Conclusions – Cat 2 HPHT wells - Drilled and
completed in open- and cased-hole with formate brines
Kvitebjørn field has produced 70 % of the original estimated
reserves by end of Year 8 – despite production constraints
• Gas production has been at a steady
6-7 billion m3/year for last 4 years – already
produced 3 billion m3 gas per well
• Need more time to see how the production
progresses towards upgraded recoverable
reserves estimate
• Good chance to compare durability of open- hole versus cased-hole
HPHT wells ?
26Formate Brine Seminar - Stavanger, 22 November 2012
27. Conclusions – Cat 3 HPHT wells - drilled with OBM and
completed in cased-hole with formate brines (no pill)
Braemar and Glenelg are both small rich-gas condensate fields
drained by single cased wells perforated in formate brines
without kill pills. Low brine losses.
• Braemar reached original est. RR figure by
Year 9
• Glenelg following same gas production track
and already exceeded 2 million m3 condensate
production by Year 5
27Formate Brine Seminar - Stavanger, 22 November 2012
28. Conclusions – Cat 3 HPHT wells - drilled with OBM and
completed in cased-hole with formate brines (no pill)
West Franklin is a «200 million boe» gas condensate field currently
drained by 2 cased wells, perforated in formate brines. Large brine
volume pushed into reservoir from well F9y
• No cumulative production data available but
was apparently producing >30,000 boe/day
in the 4 years before Elgin gas leak in
March 2012
• West Franklin Phase 2 development in
progress
Too early to get a picture of long-term production performance
28Formate Brine Seminar - Stavanger, 22 November 2012
29. Conclusions – Cat 3 HPHT wells - drilled with OBM and
completed in cased-hole with formate brines+ kill pill
Rhum and Jura are lean gas condensate fields drained by 3 and 2 cased
wells respectively, perforated in formate brines with kill pills
• Rhum : 35% recovery of gas reserves by Year 5,
before production suspended
• Jura : 27% recovery of gas reserves after 4 years
Too early to get a picture of long-term production performance
29Formate Brine Seminar - Stavanger, 22 November 2012