Stimulation Workflow Applied on LAPA Pre-Salt Carbonate Field Deep-Water Brazil

2021 ◽  
Author(s):  
Hélio Alves Pedrosa ◽  
Felipe Costa Colbert ◽  
Fernando Marques Garcia ◽  
Raphael Fernandes Gachet ◽  
Alberto Carlos Boldrini ◽  
...  
Keyword(s):  
Deep Water ◽  
Lessons Learned ◽  
Carbonate Reservoir ◽  
Fluid System ◽  
Core Flow ◽  
Coiled Tubing ◽  
Fluid Systems ◽  
Mud Cake ◽  
The Matrix ◽  
Cost Efficient

Abstract Lapa is a pre-salt deep-water field located around 270km off the coast of São Paulo, Brazil at Santos basin. This carbonate reservoir lies in water depths of around 2,100m and can produce good quality light 26° API oil. The stimulation in large carbonate reservoirs is very challenging, and techniques used for Lapa were based on chemical divergence. The development in offshore environments requires proper planning, execution, and monitoring to achieve the desired results and, of course, profitability. The matrix acidizing method was chosen to stimulate all wells of this campaign (2 producers and 2 injectors). This method consists of bypassing formation damage and stimulating the reservoir by creating wormholes via chemical pumping. In the design phase, stimulation operations previously performed at this field were reviewed, analyzed, and optimized. The main changes were regarding the completion strategy without the use of coiled tubing and placement during the completion phase as it could optimize the time and the cost for the project. The volumetric rate (gal/ft) was also reduced and the selection of the main fluid changed after several laboratory analysis and software simulations. The Lapa field requires high fluid volumes due to the length of the intended treatment interval. The assembly of a stimulation plant on a supply vessel from operator fleet (multi-purpose FSV – field support vessel) was the most cost-efficient approach to address the high volumes required as there was no Well Stimulation Vessel (WSV) available "on call" in the Brazilian offshore market at that time. This solution could also optimize the vessel fleet while the vessel was not required for pumping as FSV was also equipped with ROV and was mean to carry subsea planned task. The fluid test strategy was also a key point for this successful project as many tests were performed to make sure that the correct fluid system was selected. During this process, several fluid systems and different formulations were submitted for core flow tests and dual core flow tests to evaluate worm holing efficiency of retarded fluids and diversion performance of Chemical diverters. Compatibility tests were also performed, and a mud cake breaker was developed locally, especially for this project. This paper will bring an overview of all aspects regarding Lapa stimulation project since the conception, fluid system selection, laboratory tests, lessons learned and the potentially future strategy for this field.

Case History: Lessons learned From Retrieval of Coiled Tubing Stuck by Massive Hydrate Plug When Well Testing in an Ultra Deep Water Gas Well in Mexico

2011 ◽  
Author(s):  
Victor Gerardo Vallejo ◽  
Aciel Olivares ◽  
Pablo Crespo Hdez ◽  
Eduardo R. Roman ◽  
Claudio Rogerio Tigre Maia ◽  
...  
Keyword(s):  
Deep Water ◽  
Case History ◽  
Lessons Learned ◽  
Well Testing ◽  
Gas Well ◽  
Coiled Tubing ◽  
Hydrate Plug ◽  
Water Gas

Optimization Applied to Buzios Flexible Riser Systems and Subsea Layout

2021 ◽  
Author(s):  
Vinicius Gasparetto ◽  
Thierry Hernalsteens ◽  
Joao Francisco Fleck Heck Britto ◽  
Joab Flavio Araujo Leao ◽  
Thiago Duarte Fonseca Dos Santos ◽  
...  
Keyword(s):  
Deep Water ◽  
Technology Use ◽  
Capital Expenditure ◽  
Lessons Learned ◽  
Internal Diameter ◽  
Flexible Riser ◽  
Flexible Pipe ◽  
Injection Wells ◽  
Gas Field ◽  
Field Development

Abstract Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned. This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts. The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers. Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections. As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.

Design to First Deployment: Pressure-Activated Sliding Sleeve for Single-Trip Completion

2021 ◽  
pp. 1-14
Author(s):  
Ashutosh Dikshit ◽  
Amrendra Kumar ◽  
Glenn Woiceshyn
Keyword(s):  
Computer Aided Design ◽  
Failure Modes ◽  
Cost Savings ◽  
Lessons Learned ◽  
Design Stage ◽  
Coiled Tubing ◽  
Side Door ◽  
Safety Risks ◽  
Sand Control ◽  
The Cost

Summary Interest is high in a method to reliably run single-trip completions without involving complex/expensive technologies (Robertson et al. 2019). The reward for such a design would be reduced rig time, safety risks, and completion costs. As described herein, a unique pressure-activated sliding side door (PSSD) valve was developed and field tested to open without intervention after completion is circulated to total depth (TD) and a liner hanger and openhole isolation packers are set. A field-provensliding-sleeve door (SSD) valve that required shifting via a shifting tool run on coiled tubing, slickline (SL), or wireline was upgraded to open automatically after relieving tubing pressure once packers (and/or a liner hanger) are set. This PSSD technology, which is integrable to almost any type of sand control screen, is equipped with a backup contingency should the primary mechanism fail to open. Once opened, the installed PSSDs can be shifted mechanically with unlimited frequency. The two- or three-position valve can be integrated with inflow control devices (ICDs) (includes autonomous ICDs/autonomous inflow control valves) and allows mechanical shifting at any time after installation to close, stimulate or adjust ICD settings. After a computer-aided design stage to achieve all the operational/mechanical requirements, prototypes were built and tested, followed by field installations. The design stage provided some challenges even though the pressure-activation feature was being added to a mature/proven SSD technology. Prototype testing in a full-scale vertical test well proved valuable because it revealed failure modes that could not have appeared in the smaller-scale laboratory test facilities. Lessons learned from the first field trial helped improve onsite handling procedures. The production logging tool run on first installation confirmed the PSSDs with ICDs opened as designed. The second field installation involved a different size and configuration, in which PSSDs with ICDs performed as designed. The unique two- or three-position PSSD accommodates any type of sand control or debris screen and any type of ICD for production/injection. The PSSD allows the flexibility to change ICD size easily at the wellsite. Therefore, this technology can be used in carbonate as well as sandstone wells. Wells that normally could not justify the expense of existing single-trip completion technologies can now benefit from the cost savings of single-trip completions, including ones that require ICD and stimulation options.

Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico

2021 ◽  
Author(s):  
Frank Figueroa ◽  
Gustavo Mejías ◽  
José Frías ◽  
Bonifacio Brito ◽  
Diana Velázquez ◽  
...  
Keyword(s):  
High Temperature ◽  
Laboratory Tests ◽  
Reaction Rates ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Fluid Distribution ◽  
Acid Etching ◽  
Southern Mexico ◽  
Acid Fracturing ◽  
Fluid Systems

Abstract Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.

Increasing Operational Efficiency in Extended Reach, Offshore Wells – A Case Story from Middle East

2016 ◽  
Author(s):  
Anthony MacLeod
Keyword(s):  
System Integration ◽  
Cost Effective ◽  
Lessons Learned ◽  
Operating Efficiency ◽  
Coiled Tubing ◽  
Electric Line ◽  
Release Device ◽  
Integration Test ◽  
Closed Position ◽  
Shifting Profile

ABSTRACT Objective A case story from ME will be presented covering an extreme extended reach, offshore well. Any increase to operating efficiency can save time and increase production. In this case story two SSD's were opened in a single run on e-line, an outstanding achievement due to the ID restrictions and extended reach of the well. The paper will discuss the planning, the operation, the achievements and the lessons learned. Methods, Procedures, Process This well was recently worked over, retrieval and new installation of upper and lower completion. Due to the well going on total losses during the workover, a closed system was deployed to enable the operator to set the hydraulic packers. The packer is utilized for isolation between two zones, with each zone having two SSD's in which one SSD per zone was required to be opened to allow access to the formation. From day one of planning the primary solution for this intervention was an electric over hydraulic toolstring made up of five tools, a 218 electric release device, 218 CCL for correlation, a 218 tractor for conveyance, a 218 stroker for the mechanical manipulation and a 218 key to address the shifting profile in the SSD (toolstring). A slimhole toolstring was required due to the packer ID of 2.81" The operator was using the service provider for other interventions on this workover campaign and decided to challenge them with opening two SSD's in one run while not shifting the adjacent SSD's. The challenging underlying economics of the industry today has created a powerful driver for operators to find more efficient, cost effective and safer intervention methodologies. The operation covered in this case provided just such improvements to the client: by utilizing electric line intervention tools the operator negated the requirement for a large footprint coiled tubing intervention. Results, Observations, Conclusions A System Integration Test (SIT) was completed onshore prior to mobilization, where multiple shifts were successfully executed on a 90° deviated pipe using a single set of shifting key pads. Test results were then repeated offshore, completing two interventions in a single run. The SSD's were successfully opened at ~12,000 ft MDRT and ~8,000 ft MDRT, respectively while leaving the two adjacent SSD's in the closed position. Results, client objective was 100% achieved using only electric line, enabling the client to move forward with similar well designs having the confidence that a safe, reliable electric line solution is locally available. Additional results include reduced HSE risks as the e-line approach eliminated the use of a heavier CTU. Further contributing to the HSE benefits on this operation, only 6 persons were needed on site and no heavy lifts were required. The paper will also cover some lessons learned as debris in the profile and tubing caused some challenges. Novel/Additive Information This operation shows how the industry is constantly trying to improve on existing methods in order to be more efficient, safe and cost effective.

Experience with Chemical Injection and Umbilicals in Pre-Salt Fields

2021 ◽  
Author(s):  
Sidnei Guerreiro Da Silva ◽  
Andre Athayde Gonçalves ◽  
William Albuquerque Da Silva ◽  
Rafael Di Lorenzo Filho
Keyword(s):  
Control Systems ◽  
Deep Water ◽  
Production Systems ◽  
Poor Performance ◽  
Lessons Learned ◽  
Operational Experience ◽  
The Poor ◽  
Design Requirements ◽  
Chemical Products ◽  
Wax Deposits

Abstract The characteristics of Pre-Salt carbonate reservoirs demand downhole chemical injection to prevent scale, asphaltene, and wax deposits, besides the need of H2S scavenger, and MEG, normally injected at Xmas tree (WCT). The poor performance of injection systems installed in Santos Basin, together with production risks associated to the lack of chemical injection, led the project team to re-evaluate design requirements, such as chemical products characteristics, production systems equipments, umbilicals, and chemical injection valves. In addition, umbilical failures are being observed in other deep-water fields, related to subsea control systems functions. This paper focuses on Company operational experience and lessons learned related to umbilicals and downhole chemical injection.

scholarly journals Towards Resilient Process Networks - Designing Booster Stations via Quantified Programming

2018 ◽  
Vol 885 ◽  
pp. 199-210 ◽  
Author(s):  
Michael Hartisch ◽  
Alexander Herbst ◽  
Ulf Lorenz ◽  
Jonas Benjamin Weber
Keyword(s):  
Mixed Integer Linear Programming ◽  
Degrees Of Freedom ◽  
Optimization Problem ◽  
Critical Case ◽  
Mixed Integer ◽  
Process Networks ◽  
Fluid Systems ◽  
Vital Functions ◽  
Complete Breakdown ◽  
Cost Efficient

Resilience of a technical system is the ability to overcome minor failures and thus to avoid a complete breakdown of its vital functions. A possible failure of the system's components is one critical case the system designer should keep in mind. From another perspective resilience can be interpreted as the existence of alternative paths in a process network if resources break down. In this context we deal with process networks corresponding to systems which must be designed to operate in different scenarios. In order to ensure the system's functionality and to step in as a replacement in case of failure a set of optional resources must be available. This means that the process network must have several degrees of freedom allowing to react to uncertain events. With those restrictions we try to find a preferably resource-efficient network. Hence, an optimization problem arises which can be modeled using quantified mixed-integer linear programming. As an example of a process which can be modeled using process networks we investigate the problem of finding cost-efficient resilient topologies of fluid systems that are able to fulfill different load scenarios.

scholarly journals Diagenetic Pore Fluid Evolution and Dolomitization of the Silurian and Devonian Carbonates, Huron Domain of Southwestern Ontario: Petrographic, Geochemical and Fluid Inclusion Evidence

Minerals ◽  
2020 ◽  
Vol 10 (2) ◽  
pp. 140 ◽  
Author(s):  
Marco Tortola ◽  
Ihsan S. Al-Aasm ◽  
Richard Crowe
Keyword(s):  
Fluid Inclusion ◽  
Isotopic Composition ◽  
Age Groups ◽  
Fluid Composition ◽  
Fluid System ◽  
Negative Shift ◽  
Fluid Systems ◽  
Saddle Dolomite ◽  
Deep Boreholes ◽  
Diagenetic Fluid

Core samples from two deep boreholes were analyzed for petrographic, stable and Sr isotopes, fluid inclusion microthermometry and major, minor, trace and rare-earth elements (REE) of different types of dolomite in the Silurian and Devonian carbonates of the eastern side of the Michigan Basin provided useful insights into the nature of dolomitization, and the evolution of diagenetic pore fluids in this part of the basin. Petrographic features show that both age groups are characterized by the presence of a pervasive replacive fine-crystalline (<50 µm) dolomite matrix (RD1) and pervasive and selective replacive medium crystalline (>50–100 µm) dolomite matrix (RD2 and RD3, respectively). In addition to these types, a coarse crystalline (>500 µm) saddle dolomite cement (SD) filling fractures and vugs is observed only in the Silurian rocks. Results from geochemical and fluid inclusion analyses indicate that the diagenesis of Silurian and Devonian formations show variations in terms of the evolution of the diagenetic fluid composition. These fluid systems are: (1) a diagenetic fluid system that affected Silurian carbonates and was altered by salt dissolution post-Silurian time. These carbonates show a negative shift in δ18O values (dolomite δ18O average: −6.72‰ VPDB), Sr isotopic composition slightly more radiogenic than coeval seawater (0.7078–0.7087), high temperatures (RD2 and SD dolomite Th average: 110 °C) and hypersaline signature (RD2 and SD dolomite average salinity: 26.8 wt.% NaCl eq.); and (2) a diagenetic fluid system that affected Devonian carbonates, possibly occurred during the Alleghenian orogeny in Carboniferous time and characterized by a less pronounced negative shift in δ18O values (dolomite δ18O average: −5.74‰ VPDB), Sr isotopic composition in range with the postulated values for coeval seawater (0.7078–0.7080), lower temperatures (RD2 dolomite Th average: 83 °C) and less saline signature (RD2 dolomite average salinity: 20.8 wt.% NaCl eq.).

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