Well testing is a proven method for reservoir characterization, which is important for well-completion design, future development strategies, stimulation needs, and determining the commercial feasibility of the reservoir. This paper presents a surface data-acquisition system and its applications for rigless well-testing operations.
Drill-stem testing (DST), which is classified as a temporary completion of a well, typically involves a large and complex operation. A key activity during DSTs is collecting downhole pressure and temperature data using gauges at the bottom of the well that monitor pressure changes throughout the operation. Particularly crucial are the shut-in and initial build up, which provide insight into major reservoir properties. While shutting in the well at the bottom reduces the effects of wellbore storage, providing the most accurate downhole measurements, it also requires a rig and numerous personnel to prepare the well and run in hole (RIH) the test string. A rigless DST operation using a surface closure and surface data-acquisition system has been used in several wells to optimize data acquisition recovery as a non-invasive alternative to running downhole pressure gauges for pressure-transient well testing.
The effectiveness of the data-acquisition system provides advantages and accountability by avoiding the cost and risk of running equipment downhole and monitoring tests in real-time at surface.
The surface gauges acquire high-resolution pressure data at the wellhead during flowing and shut-in, which are then converted to bottomhole conditions using proprietary models. Because this technique is nonintrusive, it can be used to test wells in which downhole gauges are impractical or cost prohibitive, such as highly deviated, horizontal wells with tubing restrictions, sour-gas, high-pressure wells with high bottomhole temperatures, and low-cost evaluations. For mediumto high-permeability formations, a three-day test is typically sufficient to calculate basic near-bore and reservoir properties, including skin, permeability, and initial pressure. Longer tests that track pressure changes to reservoir boundaries can also be used to calculate the reservoir size.
The data-acquisition system has proven its efficacy after enabling a low-noise response and low-pressure changes resulting from temperature effects. Based on data provided by the data-acquisition system, the operator designed a well-testing campaign and achieved results typical of those expected using a conventional approach.
Fiber connectors have been used in the Subsea Oil & Gas industry for some years. As the hunger for data grows, long step outs become more common and fiber communications in other industries becomes standard, the use of fiber in subsea Oil & Gas fields is set to increase. Whilst the optical loss along the fiber itself is low and the data-collection possibilities are high, these applications, and others besides, will only be fully realised if wet-mate fiber connectors can consistently achieve high optical performance.
A fiber connection is a physical face-to-face alignment of two fiber cores which are typically 9microns (9 thousandths of a millimetre) in diameter. A tiny misalignment, stand-off or particle of contamination at the 9micron connection point could cause an unwanted optical loss. Therefore in order to achieve the required optical specifications, the optical alignment must be extremely precise and the connection must be very clean.
Achieving both of these essential criteria within a wet-mateable fiber connector is particularly challenging. The necessary pressure compensation adds to the size and complexity of the design. Not only do industry specifications require excellent optical performance but the subsea structures housing wet-mate connectors are limited for space, and product cost effectiveness in a competitive market is increasingly important.
Siemens Subsea will demonstrate how the combination of proven subsea connector knowledge, together with a compact & innovative design, modular approach and an emphasis on cleanliness in assembly has been providing consistent and excellent results. The conclusion will provide results and evidence from a thorough Qualification programme which exceeds current industry requirements.
Borehole image logs are routinely deployed in reservoir geology characterization, producing core-like images, providing geological data used in structural, geomechanical, petrophysical and sedimentological-stratigraphical analysis. Whole cores are usually acquired in key wells in areas under exploration, appraisal or development, given that they can provide direct measurements of properties of interest. Nowadays, the acquisition of oriented cores using a special core barrel assembly aligned with an orientation tool is still the most used technique. However, oriented core acquisition sometimes is precluded due to induced magnetization when the orientation tool is inside the metallic casing of the previous drilling phase. Other times, operational problems such as the orientation tool failure still occur.
The new methodology presented in this paper uses, instead of while coring orientation, core-log calibration images to link cores and image logs, unrolled cylindrical tomographies. The cylindrical tomography was developed at Petrobras Cenpes Research Center with the main aim of core orientation. Any cylindrical tomography can be oriented since image logs containing planar features suitable for geological correlation are available.
This methodology is organized in ten steps, some of them interchangeable, most of them related to the orientation of the calibration image. The main difference from others on the literature is the use of unrolled cylindrical tomography as a calibration image. Relative rotations are easily identifiable on them.
Three case studies in the presalt reservoirs of Santos basin are presented in which this methodology was successfully applied, two of them in vertical wells drilled with non-conductive mud and the third one in a deviated well drilled with conductive mud. In the two vertical wells, both acoustic and microresistivity images were available, but only one of them, both were used as references in the orientation. The lack of acoustic impedance contrast in some parts of the logged interval correlatable to the core was a reality, hence the need to use also the microresistivity images. In the deviated well, high-resolution LWD microresistivity images were applied.
The full application of this methodology makes possible to orient cores, when operational problems occur and supposedly "oriented cores" are revealed as not oriented, even if this is realized only after the liner withdraw in the core laboratory.
In accordance with the regulations in force with respect to individualization of production (unitization), the Brazilian Government does not make any disbursement to bear its share of the investments and operating costs related to the production development of a shared reservoir. Accordingly, the amount must be paid by the other parties and discounted from the volume to which the Brazilian Government will be entitled according to its working interest determined on Production Individualization Agreement (AIP). Therefore, the Brazilian Government isn't has any business risk. Representatives of private companies operating in Brazil refer to this situation as "the fourth regime", in reference to the three different exploration and production contracts in the country: Concession Contract, Onerous Assignment Contract and Production Sharing Contract. In this sense, the objective of this study is to compare the devices contained in the Brazilian legislation of the petroleum industry, regarding the individualization of the production of deposits, with the characteristics of the most common models of risk service contracts, according of the literature, and with production sharing contracts. As a result, it is hoped to contribute to the academic understanding of the subject by legislators, regulators and negotiators, representatives of the Brazilian Government and the private sector, considering that the estimated oil production from deposits that are or will be involved in significant unitization processes with the Brazilian Government.
As drilling muds evolve to satisfy well requirements, cementing preflush technologies need to change to ensure proper mud removal during cementing jobs. A new component—engineering-designed fiber—was added to a preflush fluid and tested in the laboratory, with promising results. The system was then implemented in Latin America.
Obtaining proper mud removal is very important for achieving zonal isolation at cementing jobs. The new technology consists of the addition of an engineering-designed fiber to cementing preflush fluids to significantly improve the removal of nonaqueous fluids from the well during cementing operations. The fibers are compatible with both cement slurries and mud. They work by removing the mud from the casing or formation through two mechanisms: by mechanical cleaning and by attracting the nonaqueous compound of the mud toward itself by hydrophobic-hydrophobic interaction. Two different methodologies were used to evaluate the fiber's ability to enhance the chemical wash and spacer capabilities to clean and demulsificate the nonaqueous mud fluids.
The laboratory tests were performed with cementing preflush fluids with and without the fibers. Results indicated that the preflushes with the fibers were able to clean and demulsificate the drilling mud much more efficiently than preflush without the fibers. Indeed, it was possible to optimize the amount of the preflush surfactants and still obtain excellent results. Some successful cases of field implementation of this technology corroborated the laboratory findings. In both cementing jobs, results indicated very efficient mud removal, and, consequently, zonal isolation and well integrity were achieved.
The fibers were successfully pumped in a field in Latin America. This innovative technology is able to enhance cement bonding in both casing and formation and reduces potential remedial job costs in a wide range of challenging environments.
This paper highlights the challenges to drilling risers and running equipment for offshore drilling operations from dynamically positioned mobile offshore drilling units (MODUs) in extreme water depths. Whereas nearly all exploratory drilling has occurred in water depths shallower than 3,000-m, Total recently set the water depth record with its Raya-1 well (3,400-m water depth, offshore Uruguay) using the Maersk Valiant drillship. Petrobras has also set a new Brazilian record for exploratory drilling by reaching a water depth of nearly 3,000-m. The 3-BRSA-1296-SES well was drilled to a water depth of 2,988-m the Moita Bonita area, located in the Sergipe Alagoas basin off northeastern Brazil. Several operators have leases that extend into significantly deeper water depths. This paper discusses approaches and criteria to evaluate the suitability these systems for operations in such depths. As drilling water depths increase, candidate MODUs may require additional and/or upgraded subsea and running equipment to perform drilling operations.
This paper presents a real case of wax deposition in production lines from one Brazil Pre-salt well located at Santos Basin. It also shows a diagnosis of the problem as well as the methods adopted to remove the wax.
An effective wax removal method may imply great costs, not only to implement it but also regarding the production loss involved. The best solution may not always be the one that removes the greatest amount of wax, but the one that implicates lower costs and allows operational continuity.
In order to remove wax from production line, the first method used was pig launching. The second was diesel soaking and the third and final method used was a high velocity viscous flow inducing shear tensions to the walls.
The result of each method allowed us to choose the best one regarding: production continuity, cost and wax removal effectiveness. It was possible to identify that the approach of pig launching was not effective enough. The diesel soaking approach had better result than the pigging, but generated higher costs due to the great length of the production line (9 km). The high velocity viscous flow method was the approach that gave the best results, concerning not only the amount of wax removed but also the reduced "closed well time" and costs. Repeating the high velocity viscous flow approach allowed us to optimize operation total time and the diesel consumption to perform it. The greatest conclusion was to find a method to prevent complete blockage of the production line without wasting long time of well production.
Once this was the first well from Santos Pre-salt to present wax deposition issues, this paper is an important report of good practice in dealing with such a problem.
This paper aims at exploring the different fiscal effects of field decommissioning in the Brazilian regulatory archetype and unveils the comparative law angle and resulting effect in country competitiveness and attractiveness.
Concessions and Sharing regimes (PSC) come with the inherent obligation of infrastructure decommissioning at the end of the contract. To meet such obligations, concessionaires and contractors plan the ways and costs to do so and the Regulator (ANP) approves such plan. The mechanics of how those plans are undertaken are, however, different in each of the mentioned regimes and will result in different tax impacts. These methodologies and its inherent effects will play an important role with regards to how attractive the country is for Upstream investment.
On Concessions, due to accounting rules, a provision is to be made in relation to these estimated costs. Because there are no legal grounds for deducting such a provision for corporate income tax (CIT) purposes, the deduction can only be taken at the effective cash disbursement moment, usually at the end of the field life.
The PSC law and contract provide for a decommissioning fund to be formed by the Contractor in installments. Once cash is put into the fund, the Contractor cannot take it back; even if the actual expenditure later proves to be lower, case in which the remaining funds will be reverted to the Federal Union. In the PSC, rather than a provision a definitive expense (cash into the fund) is made by the Contractor. Therefore, the definitive cash put into the fund is more inclined to generate a tax deduction.
The IMF (International Monetary Fund) has published a paper in 2012, Fiscal Regimes for Extractive Industries: Design and Implementation, where it suggests special fiscal rules for decomissioning tax deductions. Not only special rules will cause projects and countries to be more competitive and attractive, but also society may gain from its positive effects, which range from more jobs and higher income to responsible environment practices. Brazil could benefit from more competitive rules, especially after many other jurisdictions have prepared more welcoming regimes for the current low oil price world.
Khalil de Oliveira, Márcia Cristina (Petrobras) | Fulchignoni de Paiva, Lívia (Petrobras) | Meireles, Francis Assis (Petrobras) | Mendes, Rafael (Petrobras) | Dias da Silva, Plínio Martins (Petrobras) | Gonçalves Machado, Lucas (Petrobras)
Water-in-oil (w/o) emulsions are formed during the simultaneous flow of oil and co-produced water through the well and production pipelines. The viscosity increment due to stable w/o emulsion formation may lead to important production losses as friction pressure drop increases. The emulsion viscosity is affected by a number of factors, such as water content, oil viscosity, temperature, droplet size and the presence of solids. Rheological evaluations using synthesized emulsions of different Brazilian crude oils at different water contents showed the viscosity of a w/o emulsion at 50% water cut is about 5 to 9 times that of the oil and about 6 to 90 times at 70% of water cut. The experimental works presented here shows that emulsion breaker treatment is a good alternative to reduce crude oil emulsion overall viscosity and, consequently, improve production. This paper investigates this effect in two wells from Campos Basin, offshore Brazil.
For these two wells, field implementation of subsea demulsifier treatment resulted in a 47% additional oil production uplift, an increase of 3,000 bbl/d for the Company. Besides, these subsea chemical injections also promoted flow stabilization which allowed the opening of the production choke, restrained due to slug flow limitations at the top side treatment unit.
Despite the good results, further investigation was conducted to understand differences in oil production increment from each well. Thus, new laboratory tests (bench and flow loop) and multiphase flow simulations were performed based on field data in order to evaluate the difference in demulsifiers performance considering the fluid and flow characteristics. The results have shown that higher oil production is observed in wells that produce stable emulsions above 30% water cut, flowing with Reynolds number lower than 105. The additional oil production obtained in the field and confirmed by multiphase flow simulations at steady-state and transient regimes occurred primarily by the reduction of the frictional pressure drop. Secondary effects included flow stabilization, which allowed the choke opening and the consequent top side pressure reduction.
As crude oil emulsions are formed in most all oil production systems in its lifetime, the emulsion breaker’s subsea injection implementation is a concealed production uplift opportunity. The novelty of this study is in the discussion of the ability to define a criterion to select chemicals and wells to improve crude oil production in offshore systems.
Bruhn, Carlos H. L. (Petrobras E&P) | Pinto, Antonio C. C. (Petrobras E&P) | Johann, Paulo R. S. (Petrobras E&P) | Branco, Celso C. M. (Petrobras E&P) | Salomão, Marcelo C. (Petrobras E&P) | Freire, Ednilson B. (Petrobras E&P)
Petrobras found almost 100 hydrocarbon accumulations in the Campos and Santos basins, between 50 and 300 km off the Brazilian coast (under water depths from 80 to 2,400 m), which produce from very different types of reservoirs, including mostly (1) pre-salt coquinas and microbialites, (2) post-salt calcarenites, and (3) post-salt siliciclastic turbidites. These different types of reservoirs, containing also different types of hydrocarbons and contaminants provided many challenges for their production development, related to distinct tools and workflows for reservoir (static/dynamic) characterization and management, seismic reservoir characterization and monitoring, recovery methods (water injection, WAG, etc.), well spacing, well types and geometries, subsea systems, and processing capacity of production units.
Since the first oil and gas discoveries in the Campos (1974) and Santos (1979) basins, Petrobras continuously moved to aggressive exploration and production from shallow- to deep- and ultra-deep waters. During the last 40 years, the activities of reservoir characterization and management have also continuously evolved. Four major phases can be depicted: (1) shallow water fields developed with a large number of vertical or deviated wells (e.g. Namorado, and Pampo, Campos Basin); (2) deep water fields, still developed with a large number of wells, but now combining vertical/deviated and horizontal wells (e.g. Marlim and Albacora, Campos Basin); (3) deep to ultra-deep water, post-salt fields, containing light to heavy oil (13-31 °API) in siliciclastic turbidites and carbonates, developed with a relatively small number of mostly horizontal wells (e.g. Marlim Sul, and Barracuda, Campos Basin); (4) ultra-deep water, pre-salt fields with very thick (up to 400-500 m), light oil (27-30 °API) carbonate reservoirs, developed with largely-spaced vertical and deviated wells (e.g. Lula, and Buzios, Santos Basin).