Campos, Mario C M M (PETROBRAS/CENPES) | Lima, Marcelo L (PETROBRAS/CENPES) | Teixeira, Alex F (PETROBRAS/CENPES) | Moreira, Cristiano A. (PETROBRAS/UO-RIO) | Stender, Alberto S (PETROBRAS/UO-RIO) | Von Meien, Oscar F. (PETROBRAS/SUP) | Quaresma, Bernardo (PUC-Rio/Tecgraf)
The search for improvements in the production efficiency is one of the main challenges for the production engineers responsible for an asset, mainly at moments of low prices and very strict regulations for safety, environment and quality of products. Another point is that offshore plants are becoming more complex, so advanced control systems can support the operators and play an important role to improve stability and profitability.
This paper will present an advanced control algorithm for gas-lift optimization of offshore wells that aims to increase oil production. It will also show and discuss some results of the implementations of this real time advanced control system in two offshore platforms, emphasizing the economic gains and critical points to maintain this controller running with a good performance.
Floating production systems asset integrity management programs are dependent on a combination of inspection, analysis and measured data. These tasks are often labor intensive to perform. A digital twin model combines data and computer models, which can significantly increase the efficiency of these integrity management tasks. A digital twin model has been developed that utilizes typical floating systems measured data and a global performance model. This digital twin model provides an automated continuous assessment of the asset. Eliminating many of the labor intensive activities allows personnel to focus on applying the outcomes of the floating systems assessments rather than performing the assessments. The automated and continuous nature of the digital twin model also allows for a much greater understanding of the behavior of the system, which is the fundamental basis of a successful integrity management program.
Most oil production in Brazil comes from offshore fields, some of which are composed of poorly consolidated sedimentary rocks from the Miocene formation. Sand production from wells in these areas can be a significant problem, affecting the viability of field development. This sand builds up in the region near the well, resulting in damaged completion equipment and generating contaminated waste after separation. In addition to problems with sand production, some mature fields can present problems associated with the production of unwanted water and/or gas. The production of water or gas can have a negative effect on oil production because the water and gas have a lower viscosity than oil and thus can be produced easier. Also, the production of unwanted fluids can be channeled, thereby decreasing or even preventing the production of oil. Operators continuously strive to obtain cost efficiency in oil production, which encourages the development of new technologies to meet the increasing requirement of exploring unconventional fields. Several methods and technologies make development of fields with the conditions discussed viable. A combination of gravel pack placement techniques with conventional screens and an autonomous inflow control device (AICD) was first applied in an open horizontal well in the Campos basin for a major operator in Brazil. A horizontal openhole gravel pack was performed in a well equipped with conventional screens and AICD screens to help control sand production and help control water production. Several tests were performed to help ensure well requirements would be achieved. In a controlled scenario, multiphase oil flow tests were conducted to determine the performance of the AICD. The test principle was to provide pressure drop across AICD vs. water cut % curves and delta pressure vs. flow rate curves. All tests were performed and some results will be described in this paper, but the main objective was to show the successful operation performed because of the challenging scenario proposed.
Apart from being the first installation in a horizontal well for this operator, the completion schematic using two different types of screens and the low fracture gradient present in this field created a complex environment for pumping the gravel pack. The wellbore was designed with AICDs from the toe to half of the horizontal section of the open hole; the other half was completed with conventional premium screens. Swellable packers were installed between the AICDs and conventional screens. The swellable packers installed provide two different primary functions. The first is to segregate two different zones of the heterogeneous reservoir; the second is to force the flow to cross the screens per zone to allow the function of the AICD to be studied. To testify the reservoir engineer’s theory of the water reaching the toe, water and oil tracers were installed along the horizontal section and samples were collected during the life of the well. There were 72 pieces of oil tracer and 72 pieces of water tracer applied to each carrier. The application began from the center of the carrier section and was evenly distributed on both sides of the center line (oil tracer on one side, water tracer on the other). This allowed the engineers to access real data about the reservoir and the water cut through the wellbore length. This gravel pack design was the first to be reported for this type of sand control completion. The gravel pack treatment used the alpha wave/beta wave placement technique; however, it was not applied in its entirety when using screens with an AICD. The AICD has the ability to generate an additional pressure drop in high-mobility fluid, such as water. The friction pressure during the beta wave was a concern that had to be addressed because the slurry had to be dehydrated through the screen and the AICD created a choke on that flow path. Consequently, premature sandout can occur. The operational results show that it is technically possible to pump a gravel pack in horizontal wells completed with conventional and AICD screens. The significant investment involved with a deepwater environment with horizontal wells requires the most advanced techniques and best operational procedures available to help enable long-term, reliable production that is economically viable. The use of a gravel pack with a state-of-art screen provides the best solution for this offshore well in a sand and water-production field.
The Libra project is exploring and developing a very large deposit of oil and gas in the pre-salt area of Santos Basin, 100 miles offshore Brazil's coastline. Five companies have come together in a consortium together with Pré-sal Petróleo SA (PPSA) to develop this area under the country's first Production Sharing Contract (PSC). While still in the exploration phase, the project has been moving at a rapid pace, creating full field development scenarios, drilling wells, developing a system to collect dynamic reservoir information, and preparing for the initiation of its first production FPSO project. Ultimately, the field could see the drilling of nearly a hundred deepwater wells and the installation of several very large FPSOs. The area will be active with seismic, drilling, construction, production, installation and support vessels for many years.
By applying industry safety statistics to the large number of man-hours required to bring these plans to life, the potential for fatalities, Lost Time Accidents (LTI's) and other HSE incidences associated with the project can be statistically extrapolated. With these figures in mind, Project Leadership embarked upon a program to substantially improve safety performance with an objective to not only develop this rare field efficiently, but to establish a legacy of exceptional HSE performance. Now three years into Libra's exploration and development, and already exceeding 20 million man-hours expended, this paper seeks to share the steps taken to improve the HSE Culture of the Libra team and the performance of its contractors and subcontractors. Examples of physical changes in specifications to improve process safety, and changes in leadership behavior will be cited. The paper will discuss the successes, challenges, and future opportunities, in the hope that broader discussion of these efforts will assist this project and the industry to achieve project objectives while assuring safe working environments.
Offshore constructions costs can be very high when the operation requires the use of additional vessels and support tugs. This was the case in 2016, when some of the riser bellmouths needed to be replaced on one FPSO located offshore Brazil. The initial bellmouth change-out plan included an installation vessel plus support tugs to hold the turret moored FPSO in position. As a result of the current cost constraints in the offshore industry, it was necessary to challenge the conventional way of working and to re-evaluate the construction methodology. This paper presents the methodology used on the FPSO bellmouth change-out, where all operations were conducted from the FPSO, without the need for the installation vessel or support tugs.
The FPSO for this case study is located in the Campos Basin deepwater, in 1485m water depth, and approximately 70 kilometers east of Victoria, Brazil. The FPSO started production at its current location in May 2010. The unit has a maximum oil production capacity of 100,000 bopd, and a gas processing capacity of 70 mmscfd. Oil is stored onboard and offloaded through a tandem moored shuttle tanker. The gas is compressed and exported from the FPSO via a flexible riser, which connects into the Petrobras gas export system. The bellmouth change-out operations consisted of replacing the bellmouths of each of the 8 production risers. The paper will focus on engineering design and offshore operation phases to implement the bellmouth change-out in a safe, cost effective manner.
In many cases, the intensity of tide signal present in a pressure transient test is so strong as to render its interpretation unfeasible. This noise (from tide) to signal (from reservoir) ratio is a function of the transfer of tidal stresses to porous pressure as well as of some parameters from a downhole pressure test, specially, the flow rate before shut-in, formation transmissibility, shut-in elapsed time and indirectly, the wellbore skin factor.
The purpose of this work is to disseminate a predictive method of tidal effect simulation based on TMD, Tide Model Driver, with the necessary procedures and adjustments, which allows the extraction of the tidal signal components from the pressure signal recorded in wells under test through downhole pressure gauges, thus allowing analysis of test data under intense tide signal interference.
Furthermore, this work establishes a relationship between Bourdet derivative smoothing parameter
The installation of PDGs, Permanent Downhole Gauges (pressure and temperature piezo-electric sensors), in wells completed with ICVs, Intelligent Completion Valves and designed to perform extended well tests, or EWTs, has made it possible to recover characteristic tide pressure signals from relatively long periods of pressure record. In some cases, it has become possible to detach the tide signal in order to characterize it, through the Discrete Fourier Transform, DFT, determining the main tide frequency components present therein. The comparison of those frequency constituents with the ones present in oceanic and earth tide signals led to the use of a tide simulator, TMD MatLab Toolbox, as a tidal effect filter with excellent results, without the need of time lag adjustments.
The tidal effect present in pressure data from PDGs installed at oilfield wells always comes together with reservoir signal. A simple method to recover an almost pure tidal signal was developed, consisting of a polynomial fit to represent the reservoir signal. The recovered tide signal was then submitted to Discrete Fourier analysis, DFT, and the resulting frequency components were compared with oceanic and coastal tidal data available through tide stations, and later on, compared also with simulated tidal predictions, leading to the use of a tide predictor as a tidal filter. With this result from DFT, a tide signal generator, the TMD software, was selected with excellent results. A non-linear regression is run over the recovered tide data, to adjust the amplitude level of tide signal transmited to the reservoir pore pressure by rock stress. The procedure for using the TMD and necessary adjustments to conform and extract the tide signal is illustrated by a field case with strong tidal effect, to the point of totally spoiling the characteristic transmissibility levels of the pressure derivative on pressure shut-ins. On the other hand, after the proper treatment through the proposed filter, the reservoir "tide-free" signal is recovered, turning possible the analysis of the data with increased sensibility. Once the filter is adjusted to pressure data from one well, it is ready for use on other wells operating at the same field and reservoir.
The objective of this paper is to give a support decision tool to help the engineer when main equipments, especially compressors, fail for a short-period, that is to say, a few hours. This is a very complex problem since, according to the transient period of the wells, an intertemporal component is included. Until a steady state is reached again the operator must decide every period (typically every hour or every half an hour) on which wells to close or open, how much gas lift should be injected, how much the chokes should open or close in order to maximize oil production.
This paper discusses the increasing importance of intelligent completion technology in presalt developments. The Brazilian oil and gas service industry was challenged when a major oil company decided to implement large-scale intelligent completion technology for exploratory and development campaigns for two important exploration blocks, due to the limited experience and expertise in this region. The technology is considered important for reservoir risk management because of its flexibility. An intelligent completion provides a means to remotely control inflow as necessary by a reservoir management team. This additional functionality maximizes oil production and reduces unwanted water or gas influx. The technology comprises several important multizone systems, such as remotely operated flow control valves, permanent pressure and temperature monitoring, digital infrastructure, and chemical injection valves.
With limited experience and infrastructure available in the region at the time, considerable planning and interface management was necessary to ensure successful execution. The deep water presalt application imposed several challenges and uncertainties related to long-term reliability and flow assurance, such as calcium carbonate scaling, vibration, erosion, corrosion, etc. Additionally, human resources and local technical expertise along with a strong infrastructure had to be developed. Within approximately five years, the industry effort to reduce the learning curve made it possible to deliver intelligent completion technology with a proven track record into the country.
During these intensive preparation years, several key findings were realized. Standardization became important early during the process, which was crucial for accelerating learning. However, as the understanding of the technology evolved, new applications and well designs were implemented. Intelligent completions are currently being considered during all stages of the field life cycle, from extended well testing to the mature field stage, with different benefits expected for each application. With an increasing need to optimize value from the presalt wells, a holistic approach was necessary that integrated recovered data and active control into a digital platform to allow a more informed and strategic decision making process using the intelligent completion technology capability to maximize the reservoirs’ value. Results achieved to date allow a much wider application range, with increasing importance for upcoming deepwater presalt cluster development.
A milestone of 50 wells installed in several fields using this technology was achieved in the Brazilian deepwater presalt with an accelerated learning curve. Many uncertainties existed initially; however, multiple successful installations have proven this technology implementation to be reliable, with small differences in capital expenditures (CAPEX) compared to conventional wells.
The primary objectives of well construction are to maximize reservoir deliverability, reduce remedial operations, and minimize nonproductive time (NPT) during the drilling and cementing process. Challenges associated with designing and delivering dependable barriers in deepwater environments include low bottomhole circulating temperatures (BHCTs), temperature variance, narrow pressure margins, annular pressure buildup (APB), etc. Cementing operations in these conditions should be engineered such that the equivalent circulating density (ECD) does not exceed the fracture gradient during cement-slurry placement. Additionally, lost circulation materials (LCMs) should be incorporated into the cement slurry to help control loss zones. This paper discusses the field implementation procedures and the cement-slurry design tailored for deepwater wells in offshore Brazil, which helped minimize risks and achieve the zonal-isolation objectives for extending the life of the well.
The Peregrino Field is an accumulation of 13-16° API oil in the Carapebus Formation in the Campos Basin and is thereby one of the heaviest oil offshore developments in Brazil. The field was discovered in 1994 and in 2007 Statoil became a Peregrino partner followed by Peregrino operatorship in 2008. The field has been in production since 2011 by using two well head drilling platforms and one FPSO in water depth ranging between 95 to 135 m. There are 45 production and injection wells drilled so far and 15 remaining slots on the platforms. The Peregrino recovery mechanism is mainly based on reservoir depletion and rock compaction combined with aquifer pressure support and produced water reinjection in the water and oil zones.
The viscosity difference between oil and water at Peregrino gives an unfavorable mobility ratio, and water flows with a higher velocity than the oil. Any means to limit the water flow from the wells may enable an optimization of oil production. In 2013, a technology qualification program was conducted to qualify both Inflow control devices (ICD) and Autonomous Inflow Control Devices (AICD) technologies for use at Peregrino. Since then 2 wells have been equipped with ICDs and 7 with AICDs. The production experience from those ICD/AICDs wells shows that the device is best suited in areas with good pressure support, high productivity index (PI) and heterogeneous reservoir.
The paper will cover a comprehensive evaluation done for the ICD/AICD wells in Peregrino focusing on subsurface data challenges and performance predictions.