Ultra-deep Water Research Articles

Managed-Pressure Cementing Implemented in an Exploratory Ultradeepwater Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30481, “Successful Managed-Pressure Cementing on an Exploratory Well Operation in Ultradeep Waters of Mexico,” by Raul Bermudez, Juan Jose Ferro, and Cyril Szakolczai, Total, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The focus of the complete paper is the planning and execution of an ultradeepwater managed-pressure-cementing (MPC) job in the Gulf of Mexico. From the onset of planning, the base case was to integrate a managed-pressure system into the drilling program to mitigate predicted pore-pressure (PP) uncertainty, pressure ramp increase, and narrow PP/fracture-gradient (FG) window operations, including drilling, tripping, and running casing. Although MPC was not originally in the scope of work, it was required because of the tight drilling window and was successfully executed. Introduction The well is in Mexican waters at a depth of 10,748 ft. Given the exploratory nature of the well, a pressure ramp was predicted that would demand an excessive number of casing strings if a conventional approach were used. During the drilling phase—taking advantage of the ability to adjust the bottomhole pressure instantaneously—dynamic PP tests were performed to conclude that the expected pressure ramp was not aggressive but was leading to a narrow window that would not allow conventional cementing of the 13⅜-in. casing. Strategic planning and close collaboration between the operator’s engineering and operations teams, the cementing service provider, the managed-pressure-drilling (MPD) consultant, and the MPD service provider team was required. The uncertainty about the actual size of the hole led to an even more challenging MPC engineering analysis. The result of this cementing job was a success with no fluid losses, resulting in good zonal isolation. The specific objective for the MPC application was to set a 13⅜-in. casing to isolate the critical formation and safely continue drilling further stages of the well with an improved leakoff test at the shoe. Planning and design of the MPC application is detailed in the complete paper. This job represented the greatest water depth, and first from a drillship, for an MPC job performed by both operator and MPD service provider. In addition to performing a critical cementing operation using the managed-pressure approach, reaching well-construction objectives using MPD also was achieved while avoiding the use of a contingency liner, which saved significant expense. The base case was to integrate an MPD system into the drilling program to assist with PP uncertainty, pressure-ramp increase, and narrow PP/FG window operations, including drilling and tripping. The main objective for using the managed-pressure system during cementing was to ensure that the equivalent mud weight (EMW) at both total depth (TD) and the previous casing shoe did not fall below set limits throughout the job. The secondary objective was to reduce or eliminate losses during this process.

The first ultra deep water electromagnetic survey across the paleo spreading ridge of the South China Sea

The first ultra deep water electromagnetic survey across the paleo spreading ridge of the South China Sea

Alternative configurations to optimize tension in the umbilical of a work class ROV performing ultra-deep-water operation

The utilization of ROV (Remotely Operated Vehicle) for subsea operation has been increasing in the past few years alongside the increasing use of subsea technologies in deep-water oil and gas activities and other maritime operations. While survey class ROVs have reached the deepest depth in the ocean, the work class ROVs are mostly limited to 3 km depth. For a work class ROV operating in deep waters, the excessive static tension due to self-weight of the ROV and its umbilical system leaves small room before the dynamic tension exceeds the safe working load of the umbilical. Snap loads can also exist in the low-tension area of the umbilical when the ROV system is under dynamic motions which can lead to a large tensile load in the line. Therefore, there is a need for a practical solution to ensure that the safe working load is not exceeded during ultra-deep-water operation.This study focuses in reducing the tension in the umbilical hence increasing the operational depth of a work class ROV from deep to ultra-deep waters. Three different configurations, namely the hook, hook & top floaters, and mid-depth hook are numerically investigated and compared with the conventional free-flying ROV configuration. Firstly, deep-water operation of a 3 km ROV system is simulated under combination of a real extreme vertical current profile and various irregular wave conditions. This shows negligible effect of the current profile on umbilical maximum tension.The study also shows that for 3 km ROV operation, the suggested hook configuration is sufficient to effectively reduce the tension load as well as reducing the possibility of snap in the umbilical. Using hook configuration in the umbilical has significant benefits in minimizing ROV motion and also filters out the destructive snap induced high frequency tension fluctuations in the umbilical. For 6 km operation, either hook & top floaters or mid-depth hook can be utilized whereas the mid-depth hook configuration provides a broader environmental operating window for ROV operation. However, installation of floaters on the umbilical to produce the mid-depth hook configuration increases the ROV offset.

Study Investigates Using Borehole Gravity To Improve Reservoir Monitoring

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30626, “Brazil Presalt, Santos Basin: Feasibility Study for the Application of Borehole Gravity To Improve Reservoir Monitoring,” by Zhijun Du, Adrian Topham, SPE, and Jeremy C. Lofts, SPE, Silicon Microgravity, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The complete paper uses a feasibility study to present the potential application of a three-axis gravimeter borehole measurement in the Libra presalt reservoir in the Santos Basin offshore Brazil. The authors’ findings suggest that an annual survey with a limited well stock could be effective in monitoring this type of reservoir and that a wireline-deployed three-axis gravity tool is likely to provide significant additional surveillance to constrain a reservoir production strategy through better appreciation of the direction of water movement. Introduction The giant Brazilian presalt reservoirs are in ultradeep water (greater than 2000 m) and buried at a depth surpassing 5000 m. In order to conduct reservoir monitoring and achieve successful reservoir management, borehole-based geophysical technologies are preferred because the measurements can be made closer to the reservoir mass. The development of a borehole gravimeter suit-able for use in deep reservoirs, however, poses significant technical challenges, and breakthroughs have been limited by the sensor form factor (size) and measurement stabilization. By use of microelectromechanical-system (MEMS) vibrating-beam technology, the authors introduce a borehole gravimeter that enables the recording of gravitational acceleration at very high sensitivity. The new resonant MEMS gravitational sensor is designed to sense mass in the subsurface such that time-lapse wireline-based surveys can be conducted to build a picture of fluid movements at relatively large distances from a wellbore, thereby enabling time-lapse or 4D gravity monitoring. The innovation of the three-axis gravimeter also allows the acquisition of directional information about the spatial movement of fluid, even when acquired from only a single borehole. The principles of measuring gravity in the borehole environment are provided in the complete paper. Libra Field. The field is one of the largest presalt oil discoveries in the Santos Basin. It was discovered in May 2010 with recoverable resources of approximately 9 billion bbl of oil. The first appraisal well was completed and tested in February 2015. At the time of writing, nine appraisal wells have been drilled. A high-density 3D seismic program was acquired over the Santos and Campos basins, and advanced seismic processing technology has also been applied. Reservoir Simulation. The geophysics for reservoir characterization and simulation of these carbonate reservoirs is still in its early stages, and little published knowledge about their properties exists. Nonetheless, since their discovery, 2D and 3D seismic technologies have been applied intensively for imaging the region structures and delineating the reservoirs.

Overcoming Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201135, “Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field,” by Alexandre Tavares, Paulo Sérgio Rocha, SPE, and Marcelo Paulino Santos, Enauta, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition - Americas, 10-12 November. The paper has not been peer reviewed. Atlanta is a post-salt offshore oil field in the Santos Basin, 185 km southeast of Rio de Janeiro. The combination of ultradeep water (1550 m) and heavy, viscous oil creates a challenging scenario for electrical submersible pump (ESP) applications. The complete paper discusses the performance of an ESP system using field data and software simulations. Introduction From initial screening to define the best artificial-lift method for the Atlanta Field’s requirements, options such as hydraulic pumps, hydraulic submersible pumps, multiphase pumps, ESPs, and gas lift (GL) were considered. Analysis determined that the best primary system was one using an in-well ESP with GL as backup. After an initial successful drillstem test (DST) with an in-well ESP, the decision was made, for the second DST, to install the test pump inside the riser, near seabed depth. It showed good results; comparison of oil-production potential between the pump installed inside a structure at the seabed—called an artificial lift skid (ALS)—and GL suggested that the latter would prove uneconomical. The artificial lift development concept is shown in Fig. 1. ESP Design ESP sizing was performed with a commercial software and considered available information on reservoir, completion, subsea, and topsides. To ensure that the ESP chosen would meet production and pressure boosts required in the field, base cases were built and analyzed for different moments of the field’s life. The cases considered different productivity indexes (PI), reservoir pressures, and water production [and consequently water cut (WC)] as their inputs. The design considers using pumps with a best efficiency point (BEP) for water set at high flow rates (17,500 B/D for in-well and 34,000 B/D for ALS). Thus, when the pumps deal with viscous fluid, the curve will have a BEP closer to the current operating point. Design boundaries of the in-well ESP and the ALS are provided in the complete paper, as are some of the operational requirements to be implemented in the ESP design to minimize risk. Field Production History In 2014, two wells were drilled, tested, and completed with in-well ESP as the primary artificial lift method. Because of delays in delivery of a floating production, storage, and offloading vessel (FPSO), the backup (ALS) was not installed until January 2018. In May 2018, Atlanta Field’s first oil was achieved through ATL-2’s in-well ESP. After a few hours operating through the in-well ESP, it prematurely failed, and the ALS of this well was successfully started up. Fifteen days after first oil, ATL-3’s in-well ESP was started up, but, as occurred with ATL-2, failed after a short period. Its ALS was successfully started up, and both wells produced slightly more than 1 year in that condition.

E&P Notes (February 2021)

E&P Notes (February 2021)

A procedure to estimate the lateral force in clay-pipe interaction after breakout

The development of new offshore oil and gas fields is continuously expanding to ultra-deep waters. This tendency and the necessity of reducing project costs have been stimulating the development of new technologies as well as the enhancement of floating production systems. In this regard, pipelines and flexible riser systems have been getting more attention due to its low cost of installation and operation. In order to project a pipeline system, it is important to understand the pipe-soil interaction mechanisms and quantify the influence of soil behaviour on pipe response caused by lateral movement such as thermal buckling. The loads that a pipeline is subjected have been a topic of many experimental studies that aim to reproduce those loads in a realistic manner. This present study concerns the analysis of lateral clay-pipe interaction associated with large deformations and berm formation process at the leading edge of the pipe during movement at given burial depths. A series of centrifuge tests was conducted to assess the relationship between horizontal force and lateral pipe displacement. The breakout force experimental results were compared with different literature proposals, showing a good agreement. A procedure was also proposed to evaluate the normalized lateral force through the combination of two different approaches. The results showed a good comparison with the centrifuge experimental data.

Well Control Simulation With Nonaqueous Drilling Fluids

Abstract The demand for energy has increased recently worldwide, requiring new oilfield discoveries to supply this need. Following this demand increase, challenges grow in all areas of the petroleum industry especially those related to drilling operations. Due to hard operational conditions found when drilling complex scenarios such as high-pressure/high-temperature (HPHT) zones, deep and ultradeep water, and other challenges, the use nonaqueous drilling fluids became a must. The reason for that is because this kind of drilling fluid is capable to tolerate these extreme drilling conditions found in those scenarios. However, it can experience changes in its properties as a result of pressure and temperature variations, requiring special attention during some drilling operations, such as the well control. The well control is a critical issue since it involves safety, social, economic, and environmental aspects. Well control simulators are a valuable tool to support well control operations and preserve the well integrity, verifying operational parameters and to assist drilling engineers in the decision-making process during well control operations and kick situations. They are also important computational tools for rig personnel training. This study presents well control research and development contributions, as well as the results of a computational well control simulator that applies the Driller's method and allows the understanding the thermodynamic behavior of synthetic drilling fluids, such as n-paraffin and ester base fluids. The simulator employed mathematical correlations for the drilling fluids pressure–volume–temperature (PVT) properties obtained from the experimental data. The simulator results were compared to a test well data set as well to the published results from other kick simulators.

Exploratory plays from NW section of foz do amazonas basin deep and ultra-deep waters, brazilian equatorial margin

Exploratory plays from NW section of foz do amazonas basin deep and ultra-deep waters, brazilian equatorial margin

Subsea systems innovations and the use of state of art subsea technologies help the flow assurance of heavy oil production in ultra-deep waters.

Subsea systems innovations and the use of state of art subsea technologies help the flow assurance of heavy oil production in ultra-deep waters.

Buckling Properties of a Subsea Function Chamber for Oil/Gas Processing in Deep Waters

Due to the complexity of installations and connections of subsea production equipment and the massive structures involved in a challenging environment, the failure of subsea production equipment could induce enormous loss to the safety and reliability of structures in addition to the cost of the oilfield development. One of the challenges that the subsea production structures face, as it moves to ultra-deep water and polar underwater equipment, is to design subsea shell structures capable of withstanding high external pressures. Hence, a subsea function chamber (SFC) has been lately proposed as a viable solution, which has a high level of safety and reliability, and a technique for the subsea production system. This paper presents a general and efficient buckling and collapse analysis strategy. In this work, the SFC is composed of cylindrical and hemispherical shaped steel material. Initial imperfection-based nonlinear buckling analysis has been carried out to investigate the buckling and risks associated with different thicknesses of the structure. Linear and nonlinear static buckling analyses have been carried out using ABAQUS software. By introducing the nonlinear properties of materials, the nonlinear numerical model of SFC is established. The effects of the thickness of different models and the number of stiffeners on the buckling modes are discussed. The wall thickness is calculated by the Donnell equation and Timoshenko’s classical method. It has been found that the classical solutions given by the Donnell and Timoshenko equations are more accurate for structures with larger lengths and diam. The thickness and number of stiffeners have a great influence on the ultimate buckling external pressure load of SFC structure

Environmental testing for TRL 4 qualification of a novel subsea valve actuator for ultra-deep water applications

Environmental testing for TRL 4 qualification of a novel subsea valve actuator for ultra-deep water applications

Modelling oil lifting campaigns for large scale ultradeep water E&P projects: different perspectives in VUCA environment.

Modelling oil lifting campaigns for large scale ultradeep water E&P projects: different perspectives in VUCA environment.

Development of next generation subsea production system (NextGen SPS) design and analysis for ultra-deepwater applications

The present paper describes a new offshore field development solution, Next Generation Subsea Production System (NextGen SPS), that aims to overcome the technical and commercial limitations of the current offshore field development concepts (dry tree or subsea tree) in ultra-deep water (more than 1500 m). The key developments of the NextGen SPS, including its main characteristics, stability characteristics and optimal design on the riser system, are presented and discussed. The series of studies demonstrates that the NextGen SPS offers improved technical and commercial performance, higher levels of safety, reduced interface complexity and improved development flexibility for field development in ultra-deep water.

Influences of Pipelay Parameters on Dynamic Behavior of Deepwater J-Lay System

AbstractJ-lay is currently the most appropriate technique for pipeline installations in deep and ultradeep waters. Pipelay parameters can significantly influence the dynamic behavior of deepwater J...

E&P Notes (October 2020)

E&P Notes (October 2020)

Rare earth elements in drill cutting samples from off-shore oil and gas exploration activities in ultradeep waters

Rare earth elements (REEs) are essential in high technology industries and have great economic value. The monitoring of REEs concentrations in rocks from oil well drill cuttings is critical to avoid environmental contamination and evaluate new sources of these elements. However, information is scarce about the REEs concentrations in drill cuttings. In this work, the concentration of REEs in drill cuttings from oil and gas exploration wells in ultradeep coastal water of Brazilian were investigated at different depths. The drill cutting samples were submitted to microwave-assisted acid digestion prior to the determination of concentration by ICP-MS, using Rh as internal standard for calibration. The limits of quantification (LoQ) ranged from 3.3 μg kg−1 for Ho to 198 μg kg−1 for Sm. The accuracy was evaluated by analyzing certified reference materials for rocks. The obtained REEs concentrations agreed with the certified values, reaching 83%–105% agreement. The drill cutting depth profile analysis indicates Ce, La, Nd, Sm, and Eu concentrations up to mg kg−1. The REEs concentrations obtained in drill cutting depth profile was analyzed by principal component analysis (PCA), and hierarchical cluster analysis (HCA) identified tendency and similarity between drill cutting samples. Three groups were formed according to the composition of the REEs. In addition, the concentration of these chemicals elements varied at different depths. The analysis of drill cuttings revealed REEs concentrations up to the mg per kg-range (ppm), potentially making this disposable material an alternative source for REEs extraction, and adding value to this material.

Seismic Stratigraphy and Reservoir Characterization of ‘E’ Field Sediments: Inferences from South-Eastern Late Miocene - Pliocene Records, Offshore Niger Delta

Studies of Late Miocene – Pliocene continental shelf and slopes sediments on the south-eastern continental margin, Niger Delta (a broad region from the shelf – slope break extending to the ultra-deep waters: > 1500m), have revealed markedly different responses to sea level fluctuations. Significant features of the stratigraphy include siliciclastic-dominated facies consisting principally of one or more of the following genetic types: deltaic distributary mouth bars, channel and shoreface sands, barrier beach, shelf and offshore turbidites. These sands are Late Miocene – Early Pliocene in age and were deposited in deep water settings on the slope of the ‘Y’ field by a range of depositional processes that include slumps, debris flows and turbidity currents. Most of these sands could be interpreted to relate to periods of base level fall, if not Global Eustatic lowstands. Working within a sequence stratigraphic framework, eight (8) sequences have been delineated on the basis of reflection termination patterns. The major sequences were related to sea level fall during which the shelf was exposed to erosion. A cross section of the stratigraphic correlation drawn showed that the horizons are laterally continuous. However, pinch-out channel sands and lenticular sandbodies are evident. The recognition of depositional surfaces on the stratigraphic cross-sections allows subdivision of the stratigraphy into systems tracts: HST, FSST, TST and LST. On the seismic package, three (3) main seismic surfaces with distinct chronostratigraphic expressions are evident. They include non-marine, marine and fault plane surfaces. In addition, clinoform strata in the basin-margin setting of this field have relatively flat topsets and sloping clinoforms. On the shelf settings, a composite surface exists consisting of the merged sequence boundary, otherwise marked and interpreted as 4.2 Ma sequence boundary, transgressive surface (TS) and maximum flooding surface (MFS), unless separated by an incised valley fill (IVF). In the ‘Y’ field, failure, slumping and re-sedimentation processes that cause base-of-slope thickening in response to gravity and geotropic flows modify the slope. Furthermore, within the same basinal setting, affected by the same sea level rise, the facies boundaries are diachronous. Keywords: Seismic stratigraphy, Petrophysics, Sea level change, South-eastern, Miocene – Pliocene Sedimentation, Offshore Niger Delta DOI: 10.7176/JNSR/11-14-04 Publication date: July 31 st 2020

Gas transport at dense phase conditions for the development of deepwater fields in the Colombian Caribbean sea

The purpose of this article is to set out the benefits of using the dense phase gas transport in future projects in the Caribbean Sea and to verify that when operating pipelines at high pressures, more mass per unit of volume is transported, and liquid formation risks are mitigated in hostile environments and low temperatures.This study contains key data about gas production fields in deep and ultra-deep waters around the world, which serve as a basis for research and provide characteristics for each development to be contrasted with the subsea architecture proposed in this paper. Additionally, analogies are established between the target field (Gorgón-1, Kronos-1 and Purple Angel-1) and other offshore gas fields that have similar reservoir properties. Using geographic information systems, the layout of a gas pipeline and a subsea field architecture that starts in the new gas province is proposed.Finally, using a hydraulic simulation tool, the gas transport performance in dense phase is analyzed and compared with the conventional way of transporting gas by underwater pipelines, achieving up to 20 % in cost savings when dense phase is applied.

Parametric study and geomechanical design of Ultra-deep-water Offshore Salt Caverns for Carbon Capture and Storage in Brazil

This article describes a new concept to reduce carbon dioxide emissions of offshore oil production of high gas-to-oil ratio reservoirs and high content of CO2, denominated Offshore Salt Cavern Ultra-deep Water CCS (Carbon Capture and Storage) System. This hybrid system is intended for natural gas storage, the gravitational separation between CO2/CH4, and CO2 confinement for final destination. This development emerged from a current demand of some Brazilian pre-salt reservoirs to destinate a gas stream with high CO2 contamination, produced during the oil extraction. These reservoirs have a continuous salt rock layer of 2000 m as caprock making the construction possible of salt caverns by leaching using seawater. In the first stage of technology development, the system will only store a gas stream contaminated with a high concentration of CO2. In the second stage of its development, it will allow not only the separation of natural gas from the CO2 but also its storage and the monetization of CH4. This paper presents the conceptual design of this technology, showing the steps from the parametric study to select the best relation between flowrate, leaching time, structural stability, and the volume of gas with the high content of CO2 storage, up to the final geomechanical design using the set of parameters selected.