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Sempra Energy’s Energía Costa Azul LNG (ECA LNG) subsidiary reached a final investment decision (FID) to build its $2-billion Phase 1 natural gas liquefaction export project in Baja California, Mexico. ECA LNG, a joint venture between Sempra LNG and its Mexico subsidiary IEnova, is the only LNG export project to reach FID in 2020, and is slated to be the first on the Pacific Coast of North America. The facility will connect natural gas supply from Texas and the western US to Mexico and other countries across the Pacific Basin. First production from Phase 1 is expected in late 2024. The company secured a 20-year supply agreement with Mitsui and an affiliate of Total for the purchase of 2.5 mtpa and is working with Total for a potential equity investment in the facility.
Salazar Aldana, Samuel Francisco (PEMEX) | Hernández Sánchez, Rogelio (PEMEX) | Alviso Zertuche, Xavier Omar (Schlumberger) | Munoz Rivera, Moises (Schlumberger) | Camarillo Valtierra, Jose Luis (Schlumberger) | Andrade Sierra, Emmanuel Antonio (Schlumberger) | Santini Perez, Jesus del Carmen (Schlumberger) | Anleu, Pedro Leonel (Schlumberger) | Resendiz Torres, Jesus Tadeo (Schlumberger)
Water production represents a major challenge over the life of a reservoir. It is an important issue that directly affects hydrocarbon production and total reserves recovery around the world, especially in fractured reservoirs. In the south of Mexico, several naturally fractured, low-pressure reservoirs experience production disruptions when water from the aquifer channels invades oil-producing intervals through high-conductivity fractures.
Water shutoff (WSO) treatments vary in design approach and efficacy percentage due to the difference in environments and formations that are subject to water breakthrough. For the last decade, in southern Mexico, different treatments have been performed without achieving the expected results in the described reservoirs. These treatments have included different types of fluids, including rigid setting gels; reactive pills; selective water setting cement; and conventional cement slurries, with or without the use of mechanical aids such as mechanical plugs, cement retainers, or coiled tubing for precise placement.
One of the biggest challenges of WSO in these reservoirs is that the proposed treatments must have a high level of penetration into the natural fractures but, at the same time, they need to be displaced with nitrogen or light hydrocarbon derivatives to balance reservoir pressure, avoiding total losses of fluids into the highly conductive, low-pressure reservoir where they will lose the ability to control water flow from the aquifer.
Using the synergies of the operator's reservoir knowledge, diagnostic workflow, and historical treatment records coupled with service company's treatment engineering technologies and local ability to manipulate and enhance existing WSO fluids, we exercised a systematic evaluation approach to the evaluation of past unsuccessful experiences and proposed adjustments to conventional treatments using rigid gel and conventional cement slurries for water control.
Integrating the relevant findings following operator's water control diagnostic workflow with the study of relevant papers and methodologies used by oil companies around the globe, we proposed a different treatment strategy consisting in the addition of a reactive pill between the rigid gel and the cement to keep the treatment in the vicinity of the wellbore, viscous spacers between each treatment fluid to avoid contamination while traveling downhole, the inclusion of lost circulation fibers to create a fibrous net to promote cement filter-cake development and tailored treatment displacement with a predefined pressure according to reservoir condition that is close to the reservoir-equivalent hydrostatic pressure.
During the past 2 years, the application of rigorous evaluation of potential candidates and the combination of these three enhanced WSO fluids in the described sequence reduced unwanted water production in two naturally fractured low-pressure reservoirs. In three field cases, the use of the proposed methodology led to a reduction of overall water production from an initial value between 70 and 100% to levels below 30%. Incremental oil production has been maintained in the best cases for more than 2 years after the treatments. The most significant result occurred in the first field case, where the water cut was reduced from 90% to less than 2% and oil production increased 12 times, obtaining a cumulative oil production of 240,000 bbl in a year.
The documented methodology is a work in progress; we cannot replicate the technique exactly because each well presents challenges according to its construction and structural placement. Similar WSO treatments have been successfully applied in several wells in southern Mexico, increasing oil production and recoverable reserves. Continuous improvement efforts have also led to efficiency enhancement over time, as results and lessons learned are captured to be shared and replicated in similar reservoirs.
During the drilling process of exploratory wells, the formation data is often limited; most of the time drilling engineers must estimate the pore pressure and fracture gradients. This information is critical for designing the drilling fluid, spacers, and cement slurry as to provide the necessary density and rheological properties.
An error in estimating the pore pressure or fracture gradients can induce wellbore instability and lost circulation. If these losses are not controlled, during the cementing job the programmed top of cement (TOC) will not be achieved, zonal isolation will be compromised, and the casing string will not be fully supported. These problems can lead to additional expenses such as remedial jobs, non-productive rig time, use of additional materials, costly logistics, etc.
This paper presents a case history with a critical cementing job in which the operator was drilling an offshore exploratory well in Southern Mexico when an area with constant gas flow with a narrow pore-pressure to fracture-gradient window was encountered. The operator had to increase the density of the drilling fluid, which in turn induced total losses.
The cementing company recommended pumping a unique spacer technology that enabled circulation to be regained while pumping the cementing job. This technology is an ultra-low invasion cementing spacer that creates an impermeable barrier on the face of the formation through differential pressure. This barrier helps to isolate the formation from the total equivalent circulating density (ECD), thus allowing circulation even in situations where the ECD approaches or slightly exceeds the fracture gradient.
Proper well Plug & Abandonment (P&A) design requires an accurate picture of the current well status, since it represents the starting point to ensure the permanent isolation of zones with potential flow.
The greater the amount and quality of data available, the clearer the picture of the well, the better the P&A design. Then, the selection of the most suitable technologies for the specific case allows optimizing the operational sequence thus minimizing the related costs, typically around 50% of the global asset decommissioning cost.
Missing or inaccurate data at the P&A design phase results in a conservative approach, due to the many uncertainties regarding the well.
Data quantity and, mainly, quality is often dependent upon the age of assets and the existence of a proper Well Data Management System. This paper brings the P&A experience of a platform-based six-well asset in Africa, with no available well data repository resulting in a thorough "hunt for information" to generate a small database and identify the main data gaps relevant to the P&A operation being designed.
The collected data, ranging from 10 to 45 years of age, was highly fragmented and heterogeneous. For some wells, the missing information even included well construction files, cement logs, some overburden lithology parameters and, for one of the wells, the characteristics of wellhead and annulus fluid.
The execution of an uncertainty analysis based on the good practices applied in the North Sea and the Gulf of Mexico, showed that P&A cost could have varied between M$ 3.7 and 7.5 per well. The latter value was due to additional well barriers resulting from the uncertainty of well status.
Analysis of the initial BoD and potential optimization of the P&A sequence resulted in the definition of three scenarios: Best Case (full optimization), Worst Case (no optimization) and Base Case (limited optimization based on gathered information).
Two wells are discussed in this paper: Well A, with a moderate level of information, translated into an increase from the Best Case of 18%, representing around M$ 0.7; Well B, with very poor data available, translated into an increase from the Best Case of 75%, of which around 36% or M$ 1.3 related to missing information. As a result, the final P&A scenario led, for the entire asset, to an estimated increase of M$ 6 to 7 vs. the Best-Case scenario.
A simple and adequate Well Data Management System, also described in this paper, would have allowed to provide a cost-effective P&A design. The above "M$ 6 to 7" value (around 1 M$ per well) can be considered as a good indication of the value of such a system, although it is conservative in nature, since further benefits could have been also achieved during the production life of the asset.
The Square Array Void Mapping (or SAVM) seismic method is used to identify ground fissures and open voids that may affect structures built over, or adjacent to such features. It is relatively simple to deploy and can be applied to investigation beneath existing structures. The method is designed to identify and map discontinuities with greater sensitivity to these features than linear surface wave methods designed to derive the shear wave velocity structure for geotechnical design. The SAVM method uses a square array of standard single-component geophones and engineering-scale impact or vibratory sources to map variations in seismic surface wave parameters underlying the square in a frequency band corresponding to the depth range of interest.
SAVM data were collected over a series of adjacent squares along the edge of the footprint of a planned greenhouse expansion in Guanajuato, Mexico. Extensive linear ground cracks had formed beneath the existing greenhouse as the result of subsurface erosion of soil beneath a discontinuous carbonate soil layer that created voids, which subsequently collapsed. The dimensions of the greenhouse expansion required 14 square arrays of 48-meters by 48-meters to cover the perimeter of the footprint. In addition, SAVM data were collected outside the footprint in a 36-meter by 36-meter square array as a test over the projection of a known ground fissure that developed beneath the existing greenhouse. Spacing between geophones was 3 meters and a cross of geophones was located within the center of the square. A slide hammer source was used at offset 2 meters outside the nearest geophone around the edge of the square. The data were analyzed for surface wave attributes and seismic refraction velocity variations that are indicative of disruptions in the subsurface caused by ground fissures. These anomalies include a decrease in seismic wave velocities, amplitude changes or scattering. Since the fissures are linear and have a significant extent, the absence of identified fissures within the perimeter squares would indicate the absence of fissures within the full footprint of the new greenhouse.
The SAVM results identified surface wave anomalies that may represent blind ground fissures. The SAVM dataset was also processed for 3-D P-wave refraction tomography. Compressional wave velocity anomalies that coincide with surface wave anomalies increase the confidence in the interpretation because they measure different wave trains sensitive to different soil moduli. In the test square the SAVM technique showed a strong lineation of anomalous Rayleigh wave amplitude and velocity coincident with the projected trace of the know ground fissure. In one of the SAVM squares covering the proposed building footprint, we mapped linear SAVM anomalies coinciding with low P-wave refraction velocities and trending in line with the test square anomaly. Based on these results, the client was advised that subsurface exploration and possible remediation of this linear anomaly should be conducted.
Gandhi, Ankur (Occidental) | McConkey, Sara L. (Occidental) | Kimbrough, Jeremy (Occidental) | Bolingbroke, Hannah F. (Occidental) | Kapoor, Yogesh (Occidental) | Walker, Thor J. (Occidental) | Buquet, Brandon (Occidental) | Beecher, Richard E. (Occidental) | Tryon, Benjamin R. (Occidental) | Rodrigues, Neil (Occidental) | Kalich, Kevin (Arion)
Successful identification, evaluation, and management of bottlenecks in a complex, offshore production processing system—though challenging—can significantly increase daily production for the system owner. Historically, such optimization plans were developed in relative isolation of the entire production system from wellhead to export pipeline. That approach benefits simplistic systems with sufficient ullage and in which discrete changes do not affect other flow system components. However, the Constitution platform in the Green Canyon area of the Gulf of Mexico, which was commissioned in 2006 with a nameplate capacity of 70,000 BOPD, is a complex system with four fields in varying stages of development. These fields have both dry and wet tree wells with varying fluid compositions and pressures flowing through the facility, which necessitates varying process requirements, making it challenging to manage. Such a system requires a holistic and focused approach by all technical and commercial disciplines. This paper focuses on a multidisciplinary process developed to identify, evaluate, and eliminate interdependent bottlenecks on the Constitution platform and its flowline network during a 16-month period. A multidisciplinary study was kicked off in 2017 to address these complex bottlenecking issues, and the resulting project achieved a 30% improvement in deliverability of the process system.
Majors, Marc (Occidental) | Harrington, Travis (Occidental) | Ferguson, Eric (Abyss Solutions Pty Ltd) | Dunne, Toby (Abyss Solutions Pty Ltd) | Potiris, Steve (Abyss Solutions Pty Ltd) | Vlaskine, Vsevolod (Abyss Solutions Pty Ltd) | Mohammed, Jaffar (Abyss Solutions Pty Ltd) | Bargoti, Suchet (Abyss Solutions Pty Ltd) | Naqshbandi, Masood (Abyss Solutions Pty Ltd) | Ahsan, Nasir (Abyss Solutions Pty Ltd)
Risk reduction and increased Fabric Maintenance efficiency using Artificial Intelligence and Machine Learning algorithms to analyze full-facility imagery for atmospheric corrosion detection and classification. Following imagery capture and processing, deficiencies are identified, and targeted mitigation strategies are executed at greatly reduced cycle time and cost.
A pre-mobilization facility scan plan is generated to maximize imagery quality, including high elevation scan positions, to ensure thorough and comprehensive analytics. Data from all scan positions are stitched together in a point cloud and aligned for accuracy relative to each location. Finalized imagery and point clouds are then tagged with unique piping line numbers per design, fixed equipment tags, or unique asset identification. The Machine Learning algorithm is intensely trained with manual ground truth inputs prior to analysis. The algorithm analyzes each pixel throughout the facility and detects, classifies, and reports on all identified corrosion, tagging faults to specific piping or equipment.
Atmospheric corrosion is the number one Asset Integrity threat in the Gulf of Mexico. Utilizing this tool, we can have a comprehensive and objective analysis of a facility’s health in a matter of weeks from the time of data collection. Data collection for a large deep-water, spar facility requires approximately 12 days with 8 data scanning personnel. Conventional manual inspections incur higher risk, higher cost, and reporting is much less objective considering the number of inspectors involved and the duration of a full-facility campaign. Finally, all results are published in a user-friendly dashboard that can be filtered by process type, equipment type, corrosion severity, and many other criteria as the user requires. Each fault is associated with the specific equipment identification and the user can navigate to see the imagery of the corrosion in a 3D, photogrammetric environment. Remediation strategies can be collated into work packs for fabric maintenance teams, further Nondestructive Examination (NDE) assessment, or work orders for replacement. Fabric maintenance efficiencies are substantially realized by targeting decks, blocks, or areas with the highest aggregate surface areas of corrosion (on process equipment or structurally, as selected by the user) and concentrating remediation efforts on at-risk equipment.
This application of Artifical Intelligence and Machine Learning is a first-in-industry approach to having a comprehensive understanding of facility coating integrity and external corrosion threats. HSE analysis, Risk awareness, and targeted remediation strategies will make the Asset Integrity program more efficient, proactive, and reduce down-time across the Gulf of Mexico related to atmospheric corrosion.
McDermott moved its second shipment of topside modules for MODEC’s Miamte MV34 floating production, storage, and offloading (FPSO) unit from its Altamira fabrication facility in Mexico. This follows McDermott’s first shipment of modules from Altamira in October. The modules will travel from the Altamira fabrication facility to Singapore where integration will be performed at the Dyna-Mac fabrication yard. The scope of the work comprises five FPSO topside modules, delivered in two shipments. This second shipment includes modules that provide inlet separators, oil separation, a flare knockout drum, and sand-cleanup materials.
Bermudez, Raul (TOTAL) | Ferro, Juan Jose (TOTAL) | Szakolczai, Cyril (TOTAL) | Birades, Christophe (TOTAL) | Conil, Luc (TOTAL) | Hernandez, Julian (Weatherford) | Brinkley, Ryan (Weatherford) | Arnone, Maurizio (Weatherford) | Carreño, Leonel (Weatherford) | Hollman, Landon (Blade) | Torres, Ivan (Halliburton)
The operation described in this paper is related an ultra-deep-water exploration well drilled in the Mexican waters of the Gulf of Mexico (GOM) and the first drilled by the operator in the area. From the onset of planning, the base case was to integrate a Managed Pressure Drilling (MPD) system into the drilling program to assist with pore pressure uncertainty, pressure ramp increase, and narrow Pore Pressure/Fracture Gradient (PP/FG) window operations including drilling, tripping, running casing and cementing, with the latter being a procedure that was not included in the initial stages of the project but discussed and implemented during the execution phase (
The well is located in a water depth of 3,276 m (10,748 ft). Given the exploratory nature of the well, there was an assumed pressure ramp that would demand an excessive number of casing strings with a conventional approach using an overbalanced Mud Weight (MW). During the drilling phase and taking advantage of the ability to adjust the bottom hole pressure instantaneously, dynamic pore pressure tests were performed to conclude that the pressure ramp was not as aggressive but lead to a narrow window that would not allow conventional cementing of the 13-3/8-in. casing.
Strong planning was required between the operator's engineering and operations teams, cementing services provider, MPD consultant, and MPD service provider team. The uncertainty about the actual size of the hole yielded an even more challenging Managed Pressure Cementing (MPC) engineering analysis (
The specific objective for the MPC application was to set 13-3/8-in. casing to isolate the critical formation and to safely continue drilling further stages of the well with an improved Leak-off Test (LOT) at the shoe.
This job represents the deepest water, and first from a drillship, for a managed pressure cementing job performed by both operator and MPD service provider. Additionally, a critical cementing operation was successfully performed using the Managed Pressure (MP) approach. The well construction objectives using MPD were also achieved while avoiding the use of a contingency liner which saved an additional USD3.5 MM from the planned AFE (
The oil and gas industry has picked up on the benefits of digitization and artificial intelligence (AI) in its day-to-day activities, and the health, safety, and environment (HSE) sector is no exception. While AI brings clear benefits, the risks that come with those benefits remain unclear. While touting the advances of technology in HSE at SPE’s Virtual Annual Technical Conference and Exhibition (ATCE), Olav Skar, director of health, safety, security, and wells at the International Association of Oil and Gas Producers (IOGP), said, “I also see risks, and I remain concerned that we do not truly understand them.” Skar spoke at ATCE on a panel that included Mohamed Kermoud, Schlumberger’s global vice president for HSE, and Philippe Herve, the vice president of energy solutions at SparkCognition. The panel was moderated by Josh Etkind, Shell’s Gulf of Mexico digital transformation manager.