This paper discusses the historical evolution and future performance of wellbore dynamics in a multilayered gas condensate well (100 MMSCFD) in the Camisea Field - Peru. The analysis included the modeling of water vapor content produced within the gas condensate stream and its multiphase behavior and interaction with other fluids inside the borehole through the reservoir depletion under commingled production. The goal of this study is to quantify the impact of the wellbore dynamics in well deliverability and the effective recovery of hydrocarbons for each individual layer, and propose actions to achieve an optimum production scheme.
The approach is based on the modeling and matching of dynamic behavior of the wellbore and individual layers with the observed data during 9 years. For this purpose a dynamic wellbore model was built using OLGA. The inputs to the model are: 1) the properties for each productive layer characterized using multirate test combined with PLT logs to get the individual IPR's; 2) the model of the reservoir fluid to properly represent the retrograde condensation and the behavior of water in the vapor phase; and 3) the liquid levels in the wellbore from historical PLTs and density logs.
In the field case studied, the analysis showed that the water vapor present in the fluid stream is a fundamental key to understand the evolution of fluid levels inside the wellbore. This is quite important since the water in the gas phase is not usually included in the EOS for reservoir simulation purposes and its impact in the wellbore dynamics is neglected because of the very low BSW (less than 1%). For the well that has been studied, the analysis revealed that the lower zone was prone to stop producing due to the higher productivity of the upper reservoirs. Consequently, the increase in liquid level was a result of the production decrease and not vice versa. After the lower layer stopped producing, it was observed that there was a quicker increase of the liquid column between the upper and lower reservoirs. This column was mostly condensate but it was gradually replaced by water in the liquid phase, which came from the vapor phase produced in the upper reservoirs. This slow replacement represents a more restrictive condition for the lower reservoir, as the column becomes denser.
This study allowed for the understanding the complex interaction between retrograde condensation and water vapor behavior with the wellbore dynamics. The study also describes the process of the liquid accumulation during the decline of production of multilayered reservoirs which was successfully matched with observed data. As a result of the analysis, a new completion scheme was proposed to effectively recover the hydrocarbons in the layers affected by liquid loading issues.
In 1993, Richard D’Souza (Fellow), the principal author and his co-authors presented a landmark paper reviewing the Semisubmersible Floating Production System (FPS) technology at the SNAME centennial meeting in New York. (D’Souza et al., 1993a). The paper captured the twenty year progression of the FPS beginning with the Argyll field in the UK Sector of the North Sea in 80 meters of water that was converted from a semisubmersible Mobile Offshore Drilling Unit (MODU) and began producing in 1975. During this period about twenty five FPSs were installed, primarily in the North Sea and Brazil. Most were converted from semisubmersible MODUs. The deepest was in 625 m, the largest displacing 45,000 mt and the maximum oil rate was 70,000 bopd.
Over forty FPSs have been installed since then, most of which are purpose built platforms. The technology has expanded to a maximum water depth of 2400 m, displacements exceeding 150,000 mt and production rates of 300,000 boepd. The inherent versatility and flexibility of the FPS to adapt to a wide range of water depths, payloads, metocean conditions and future expansion, has resulted in the FPS superseding the Tension Leg Platform (TLP) and the Spar platform as the most widely used floating production platform after the Floating Production Storage and Offloading (FPSO) platform. Its field development applications range from marginal reservoirs to giant deepwater oil and gas fields across the globe.
This paper, authored by Richard D’Souza with a new team of co-authors, is a sequel to the 1993 paper and is intended as a historical and technical archive of the evolution of the FPS technology in the ensuing twenty five years. It highlights the importance of the Naval Architect and Ocean Engineer whose role has evolved from a peripheral to a major player in the design, fabrication and installation of the FPS. This paper has two objectives. One is to inform Operators and Contractors engaged in developing deepwater fields by providing a historical overview of lessons learned and technology evolution of the FPS. The other is to inspire graduate and post graduate Naval Architects and Ocean Engineers to consider a career in the offshore industry where they will have an impactful role in shaping the future of deepwater floating production platforms.
Mature heavy oilfields in the Northern Peruvian Jungle have produced oil for more than 40 years under primary recovery mechanisms (cold methods). As these fields are exploited by a strong water drive assisted with ESPs, total oil production has surpassed more than 1 billion barrels of oil with an average 15% primary recovery factor; ultimate recovery is expected to account for 17% at an economic limit of approximately 98% water cut. According to the
This study explores the development options (technical an economic) to produce heavy oil resources at commercial rates and showcases three optimization scenarios of higher recovery efficiency (additional 5%, 10% and 15% RF) utilizing current technology and sensitizing their economic variables with the main objective of increasing the net present value at the basin level. This is achieved by exploring and validating synergy strategies available in the basin and proposes investment for the Norperuano pipeline revamp to pump light oil/diluent to heavy oilfields (e.g Block 67) and make transportation of volumes currently classified as resources feasible. Lastly, this paper shows the current royalty framework in the Loreto region on a block basis and explores the financing alternatives to foster development and exploration activities in the North Peruvian Jungle heavy oilfields.
The workflow starts with identifying heavy oil development strategies, prioritizing and selecting the most appropriate technologies to optimize production performance and increase recovery efficiency; then, infrastructure options and financing alternatives are carefully reviewed to ensure heavy oil is produced with an appropriate amount of diluent. Finally, royalty and other tax incentives are suggested to ensure a profitable exploitation of heavy oil resources. Typically, primary recovery factors for heavy oilfields range between 10 to 15% with several alternatives for development such as multilateral drilling, steam flooding and HASD which would at least double production rates and increase recovery factors by 10% to 15%. Pilot tests of thermal recovery methods are strongly recommended for some fields in early development stage such as the Bartra field in Block 192 and the Raya and Paiche fields in Blocks 39 and 67 respectively. In order to handle new production rates, modifications to the Norperuano pipeline are proposed; additional in-situ loops and a parallel new pipeline are suggested, not only to ensure diluent/light oil transportation to supply the heavy oilfields, but also to increase transportation capacity of diluted oil to surface storage facilities and to the Refinery Complex in Talara; located on Peru's northern Pacific coast which is currently undergoing an expansion from 65,000 bopd to 95,000 bopd due by November 2020.
Assuming the first two conditions are met (the increase of production rates and recovery factors, and the egress constraint is no longer relevant) the profitability of the project at the basin roll-up level must be tested with a reserves model with inputs such as production rates by block, operating and capital expenditures for the different reserves/production wedges, royalty rates and taxes. The model must be consistent with the development program proposed by the operators in the region and be run at different pricing scenarios to stress-test the break-even value at several levels.
Mendoza, Maria (Petroamazonas EP) | Cevallos, Gonzalo (Petroamazonas EP) | Molina, Edison (Petroamazonas EP) | Piñeiros, Silvia (Petroamazonas EP) | Torres, Water (Petroamazonas EP) | Garrido, Johnny (Petroamazonas EP) | Gutierrez, Ruben (Schlumberger) | Fonseca, Claudio (Schlumberger) | Cortez, Oscar (Schlumberger) | Fernandez, Edgar (Schlumberger) | Paladines, Agustin (Schlumberger)
An Ecuadorian lease ("Bloque 61") composed of 14 oil fields represents the most productive asset in the country. It contains 5.3 billion barrels of original oil in place (OOIP) distributed in four complex producing reservoirs. After 44 years of production and with a decline rate of 31% per year, maintaining the production from these fields represents an important challenge from the subsurface and execution viewpoints. In December 2015, an integrated service contract was signed with the national oil company (NOC) with a fixed investment for the development of the entire lease.
The challenge of the project was to maximize the value of a depleted asset through the framework of the c ontract. This mature asset has many opportunities to boost production and reserves by implementing an aggressive fit-for purpose development. The opportunities screened and implemented in only 12 months consisted of reaching new oil in appraisal and exploration areas and redevelopment of mature zones with horizontal and infill drilling with mainly reentry wells. Most valuable of all was the implementation of six waterflooding projects. All of these were executed in the Amazon rainforest where there is a pressing need to reduce environmental and social impact.
This exploitation philosophy has successfully changed the asset's production decline, ramping production up from 60,000 BOPD to 80,000 BOPD. This integrated field development plan has amalgamated several technologies with a specific objective of optimizing the value of the asset. The long term was assessed through the drilling of exploration and appraisal opportunities where prospective resources were recategorized to reserves. The medium term was tackled by drilling horizontal wells and re-entries to optimize sweep efficiency and implementing water injection in the main structures. The short term was directed by executing workovers in areas where the water injection was in place. The asset value was recovered and increased as shown by a reserve's replacement ratio of 1.13.
This approach will serve as a framework for the future integrated development of these types of mature assets. The technologies implemented have helped accelerating and optimizing the conceptualization and execution of the project; a few of these include high-resolution reservoir simulation, dumpflooding, closed-loop water source system, and dual-string completions. The integration of strong domain expertise, coupled with advanced technologies and workflows, has led to outstanding results.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Summary As the 1960's ended, seismic was in the process of its most fundamental transition as we converted from analog to digital acquisition and processing. This conversion allowed us to explore for increasingly more subtle targets and has allowed oil production to keep pace with the everincreasing demands of both developed and emerging societies. In hindsight, the transition was perhaps one of the most significant developments in all human history. The modern ease of transportation has revolutionized all aspects of human society, a revolution that it is fair to say could never have occurred had we been confined to the limits of analog seismic. Today, we are at the forefront of a reverse transition, as we progress from interpreting digital images of seismic amplitudes to working, visually, with the analog seismic wavefield.
In seismic processing of multi-component data, converted shear waves are generated from incident pressure waves P at subsurface reflectors. Imaging with converted waves provides an opportunity to improve the seismic image in challenging areas where the PP reflection is poor. Handling strong lateral velocity variations and shallow complex structures requires high accuracy algorithms, such as reverse time migration (RTM) or full waveform inversion (FWI). For such algorithms, accurate wavefield simulations are crucial. In this paper, we propose an algorithm that can be used to efficiently simulate the 3D quasi-P and quasi-SV waves in anisotropic media. The algorithm may be considered as an asymptotic approximation of elastic wave equations such that the calculated wavefield is accurate in phase and robust in amplitude. Its applications could include RTM or FWI for PS imaging. We validate the accuracy and efficiency of the algorithm with a simple VTI model and a SEG SEAM TTI model.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 207A (Anaheim Convention Center)
Presentation Type: Oral
The development of an offshore oil field is a complex and risky project. One core problem in this task is the selection of a production system that maximizes oil recovery and minimizes investments and operational costs while meeting external, economic, environmental, societal and technological demands in a scenario of uncertainties. Several studies address this problem in the literature; however, they do not consider uncertainties in the initial data neither justify objectively the chosen alternative among other feasible ones. We propose to select an offshore production system using an intelligent system that considers input uncertainties and chooses the best alternative in a rational manner. By comparing the results obtained with previous studies and real scenarios, we conclude that our methodology can obtain the optimal solution in situations where other methods cannot.