bluuebunny/crossref_metadata_2025 huggingface dataset:
Subsea Induction Heating Technology Solves Hydrate and Wax Issues in Subsea Flowlines
Authors: Anres Stephane , Hallot Raymond , Valdenaire Thomas , Macauley Lionel
Published: October 2019

A new technology called local heating offers the possibility of significantly raising the temperature of the multiphase production fluid in order to improve flow assurance and consequently the economics of field developments. Heating the flowlines is a way to overcome the thermal constraints, mitigate hydrate & wax risks and provide operational flexibility. Indeed, in the case of long distance tie-backs, very deepwater applications or when the fluid temperature at the wellhead is too low, conventional flow assurance solutions might be very expensive or even not applicable.

While other heating technologies such as DEH and Heat tracing are only used under transient operations (start-up, shutdown, preservation), local heating is a different solution, mainly to be used continuously during production and also during transient operations as long as there is fluid circulation in the flowline. The local heating device is a very simple and robust system integrated into a compact subsea module, installed in parallel of the main flowline and which can be retrieved for maintenance or relocated. The technology is compatible with any type of field architecture and can be implemented either on greenfields or brownfields. In the case of greenfields, the use of local heating is a way to mitigate uncertainties on production fluid temperature or solve an unexpected poor thermal performance of the design.

The main principles of the local heating technology, as well as a preliminary design performed for a specific case provided by an operator, will be described in the paper. This solution is based on induction and is therefore able to provide very high-power levels (several MW) with a compact module. The temperature is continuously monitored throughout the heating module by means of fiber optic distributed sensors. The technology is fully compatible with preservation by flushing and allows pigging in the event of deposits.

The paper will also present the qualification work performed by Saipem to date including heating performance tests performed mid-2018 on a small-scale submerged prototype operated under atmospheric conditions with multiphase fluid. The tests have confirmed the good electrical and thermal behaviour of the system.

The next qualification step entails new tests to be performed on a medium scale prototype using crude oil as process fluid. The main objective is to qualify the heating performance tests and the fabrication method of the local heating module under representative conditions: representative process fluid and representative module geometry. The intention is to perform these tests on an existing Brazilian onshore test site in the frame of a JIP.
Effective Cross Flow Diagnostic by Pulse Neutron, Cement Logs and Fluid Production: Water Shut Off Well Case in Amo Field
Authors: Orellana Ney Holguer , Gaibor Andrés Mauricio , Astudillo Ricardo Andrés , Lozada Santiago Fernando , Muñoz Edwin Raúl , Tamayo Telmo , Bailón Luis Roberto , Padilla Carlos Alberto
Published: October 2019

The high water cut 98,5% caused the abandonment of a directional well, which was reactivated after 3 years using a water shut off technique. Offset wells production behavior, stratigraphic seal layers distribution, reservoir properties, and cased hole logging data played a relevant role for the well planning, reactivation and production success of heavy oil from the mature Amo field in the Oriente Basin of Ecuador.

The Lower U reservoir production screening from neighbor wells and stratigraphical well correlation supported a rigless acquisition plan of pulse neutron logs to diagnose the fluid flow patterns after 5 years of production and 3 years of a well abandonment. Further corrosion and cement log was run to check the well integrity and compared it with initial cement log to discard possible cement channeling suspicion behind casing. Finally, water shut off well program was carried out.

The acquired neutron logs showed flushed zone from two former producing perforations as well as remaining hydrocarbons in the upper perforated zone. The gamma ray log activation was detected just below the oil water contact while the oxygen activation log "OAI" was highlighted just above the gamma ray activation at the same depth where CBL log experienced picks perturbations suggesting bad cement an possible channeling behind casing. The OAI ended just in the upper unit perforations where another CBL pick was recorded. These evidences supported possible cross flow hypothesis from the bottom to the top producing zones. The water shut off job squeezed the lower perforation zone and re-perforated the upper unit to reactivate the abandoned well. The cement and corrosion logs suggested a good conditions of casing and zone isolation from aquifer. The well reactivation produced 700 bbl/d of water formation (100% BSW) during a month, the water salinity gradually increased from 16000 ppm to 45000 ppm NaCl. Likewise water cut diminished to 17% and 170 bbl of oil was pumped daily after voiding the cross flowed fluid (44000 bbl). Furthemore, the unknown productivity index for ESP pump design was unveiled.

Stratigraphic well correlation indicated the shale layer continuity and thickness variability, which in combination with shale buffers occurrence were controlling the production behavior in offset wells. These aspects led to get updated cased hole logging data to identify opportunities for re-activation of abandoned well unlocking by-passed oil reserves after successful water shut off job execution.
Ecotoxicological Evaluation of Non Aqueous Drilling Fluids Using a Brazilian Native Versus an Exotic Amphipod
Authors: Kraus Leila Aparecida da Silva , Melo Sônia Lopes Rezende de , Reynier Marcia Vieira , Marinho Leonardo de Souza , Veiga Letícia Falcão , Pereira Bruno Correa , Araujo Leandro Franco Macena de , Ximenes Dalton de Sousa
Published: October 2019

Brazilian Environmental Authority (IBAMA) adopted EPA rules for discharging drill cuttings from O&G operations. EPA method describes procedures to evaluate toxicity using Leptocheirus plumulosus. Despite being an exotic species, Brazilian laboratories keep L. plumulosus cultures. Otherwise, Grandidierella bonnieroides is widely distributed in Brazilian estuaries is successfully cultured and sensitive to many toxicants.

The present study was carried out to evaluate the effects of three non-aqueous drilling fluids (NAF) and two synthetic based drilling muds (SBM) spiked to natural sediment on the amphipods. Reference toxicant experiments were also performed using C16C18 internal olefin or a C16C18 internal olefin SBM of similar density.

Sediment was collected in Jabaquara beach, RJ and transferred to the laboratory in chilly bins. After sieving, it was kept at 4 ± 2 °C until spiking for no longer than 60 days. Spiking procedures and whole-sediment tests were set up following the methods described in EPA method 1644 and Brazilian Standards. Amphipods were exposed to 5 concentrations of SBM and NAF spiked sediment plus controls for 4 and 10 days, respectively, in static system.

In NAF tests using G. bonnieroides the average LC50 obtained were 3.53 g.kg-1dw (n= 7; SD=1.63; CV= 46.07%), 1.33 g.kg-1dw (n= 6; SD=0.69; CV= 52.15%) and 0.56 g.kg-1dw (n= 7; SD=0.24; CV= 42.69%) for olefin, ester and paraffin, respectively, while L. plumulosus showed an average LC50 of 1.66 g.kg-1dw (n= 6; SD=1.30; CV= 78.10%), 0.60 g.kg-1dw (n= 5; SD=0.22; CV=35.81%) and 0.26 g.kg-1dw (n= 6; SD=0.13; CV= 50.50%), respectively. The average LC50 obtained in SBM 1 (11.6 ppg) tests using G. bonnieroides was 139.78 mL.kg-1dw (n= 3; SD= 69.47; CV= 49.70%) and for SBM 2 (9.9 ppg) the LC50 was 132.97 mL.kg-1dw, while L. plumulosus showed an average LC50 of 94.79 mL.kg-1dw (n= 2; SD= 92.33; CV= 97.41%) LC50 of 34.82 mL.kg-1dw, respectively, for SBM1 and SBM2. In olefin tests using L. plumulosus, SBM 2 test using G. bonnieroides and SBM 1 tests using both species, STR ≤ 1 were obtained, meeting the EPA criteria for drilling cuttings discharge. Although G. bonnieroides has shown to be less sensitive than L. plumulosus to the NAF and SBM, the method using G. bonnieroides as test species demonstrated to be suitable for this purpose and presented similar variability than the same method using L. plumulosus.
Case Studies: Opportunities and Challenges in Brazilian Mature Fields' Subsea Conceptual Design
Authors: Cabral Gabriel Rodrigues , da Silva Helvio Ferreira , Bressan Robert da Silva
Published: October 2019

When performing any redevelopment or complementary project assessment, there are usually common characteristics that an operator could face, for instance reuse of existing assets, marginal fields, etc. However, due to project development strategies in Petrobras and Brazilian regulation and scenarios, there are some specific additional challenges, such as environmental constraints. This paper aims to present actual case studies from Brazilian fields, highlighting some challenges, opportunities and keys to success with associated results, that ensured projects technical and economic feasibility. By the end of this paper, one should realize that challenges and opportunities faced in Brazilian mature fields' subsea design are often similar from a broad perspective; hence, the keys to success can also be reproduced from scenario to scenario, with few specific adaptations, case by case. Such conclusion allows a portfolio approach, anticipating challenges and, thus, motivating the development of desirable novel solutions, such as new technologies and methods of methods. This will lead to saving costs and reduction of risk and time of deployment.
A Study of Directional Drilling Using Rotary Steerable System in Soft Shallow Formation Benin Sand – Rio Del Rey Area, Offshore Cameroon
Authors: Oredolapo Olawale Majeolatan , Onomo Claude Placide
Published: October 2019

Rotary steerable tool has been proved reliable tool that can be used in different types of formation. But in the Rio Del Rey area in the "Benin sand" in Offshore Cameroon, directional drilling issue have been faced while drilling with rotary steerable tool.

This paper present a case of study on the importance of the Bottom Hole Assembly choice versus the lithology, BHA Configuration, bit selection and trajectory requirements. Also based on lessons learned, propose some recommendations.

Rotary steerable is deemed to be a reliable tool that can be used on most of type of formation but this is not always the case as shown in our case of study while drilling through the Benin sand formation which is a shallow formation in Rio Del Rey field in the Niger Delta, offshore Cameroon using the rotary steerable system. RSS BHA has been observed to perform below expectations while drilling this formation. A holistic review of the operational performance of the five Bottom Hole Assembly that was run in the hole to drill ~1000m of soft sandy formation will be summarized. We will analyze each BHA that was ran in hole and the performance achieved. Also BHA configuration and trajectory will be evaluated and reviewed. Finally, some recommendation are made. In addition, the choice of bit selected and performance will be evaluated.

After detailed analysis of each BHA, RSS BHA with PDC bit was seen not to be a good choice of BHA to drill through the Benin sand formation based on the well directional objectives and BUR requirements. Motor BHA with tricone bit using the principle of jetting was used along with catenary design trajectory. This BHA and bit selection choice with catenary design trajectory helped to achieve the directional objective 100%, even exceeded the required DLS at some point. Also, adjusting drilling parameters contributed to the success seen so far.

However, some irregularity was observed in the dogleg severity which may need an additional run with the rotary steerable system to smoothen the trajectory or perform a control trip in this soft formation with the potential risk of accidental sidetrack.

In conclusion, a Motor bottom hole assembly with tricone bit using the principle of jetting should be used if a risk of collision is highlighted and a need to build up quickly in order to move away faster from nearest wells.

A motor assembly is more recommended in soft shallow formation (0m −700m TVD) than the rotary steerable system. A better BUR behavior was observed with a motor assembly.

This paper will serve as a guide / recommendation for any drilling that requireds an aggressive shallow kick off due to collision concern in soft shallow surface formation where performance of the bottom hole assembly and bit selection is critical.
Effect of CO2 Injection on the Interfacial Tension for a Brazilian Pre-Salt Field
Authors: Drexler Santiago , Correia Elton L. , Jerdy Ana Carolina , Cavadas Leandro A. , Couto Paulo
Published: October 2019

Interfacial tension (IFT) between oil and brine plays a key role in determining the capillary forces in the porous medium. When studying Enhanced Oil Recovery (EOR) methods, it is of great relevance to characterize the IFT. In the case of Pre-Salt reservoirs, CO2 and water alternated with gas injections are being considered as EOR techniques. For paraffinic oils, such as alkanes, the presence of CO2 decreases the IFT between oil and brine. However, for Pre-Salt oils with high concentrations of asphaltenes and resins, the effect of CO2 injection on the oil-brine IFT has not been reported. This work uses the drop shape analysis technique to measure the IFT between a Pre-Salt crude oil and synthetic brine with the composition of formation water in the presence and absence of CO2. The results were compared to those obtained for synthetic oil consisting of alkane and aromatic molecules. For the crude oil, CO2 dissolution, which decreases brine pH, increased the IFT between oil and brine. Oil characterization retrieved high concentration of asphaltenes and resins and considerable acid and basic numbers. In addition, infrared spectroscopy and nuclear magnetic resonance of the asphaltene fractions of the crude oil reported acid functional groups in these polar compounds. Therefore, the surface activity of the polar compounds in the oil may be reduced at lower pH. On the other hand, for the synthetic oil, CO2 decreased the IFT as previously reported for alkane molecules. Therefore, this work shows the difference in the effect of CO2 on IFT, which depends on the composition of the oil and aqueous phases. Furthermore, the acid/base characterization of the polar compounds is relevant to understand the effect of CO2 dissolution on the resulting IFT.
Technical Economical and Risk Analysis Methodology for Defining the Optimum Positioning of the Electrical Submersible Pump System for Production of Heavy Oil in Deep Water
Authors: Cavalcante Barbara Ferreira , Baioco Juliana Souza , Jacob Breno Pinheiro , Urupukina Nicolas Paes
Published: October 2019

In an oil field development, the choice of the appropriate artificial lift method is extremely important to obtain the best financial return for the project. The most efficient artificial lift method for heavy oil is the ESP, in the perspective of lift capacity and flow assurance, but, due to its low MTTF (Mean Time to Failure), in some cases, the associated cost for the offshore workovers is prohibitive. An alternative to reduce the cost of the workover is positioning the ESP in the seabed, in a pumping skid (Subsea ESP / skid-ESP). Positioning the ESP in the seabed, however, reduces the initial well flow rate. Most commonly, the Artificial Lift Method is chosen based on the previews experience of the operator, not giving appropriate effort to a technical and commercial evaluation. This paper proposes a methodology to provide quantitative data to assist the decision of the best positioning of the pumping system, inside the well or on the seabed, in order to obtain the best financial return.

The methodology is based on three stages: technical evaluation, which is an eliminatory step, based on the GVF (Gas Volume Fraction) limit that the pump can handle without flowing problems; then, an economical and risk analysis are performed for both projects (ESP and skid-ESP). Three case studies were performed to evaluate the proposed methodology, and to confirm that it is a good tool to assist the decision of the best positioning of the pumping system.

The results show that the three stages proposed are important. One of the three cases show a scenario where the skid-ESP is declassified in the first step of the methodology because of the high GVF calculated for the project, above the limit for this specific well. In the other two cases all the three stages of the methodology were applied. The economical deterministic analysis was not enough to define the best positioning of the pumping system, in order to obtain the highest financial return, and the probabilistic risk analysis was essential to obtain quantitative data to support an efficient decision. In both cases the suggested positioning of the pumping system was the seabed (skid-ESP or subsea ESP).

In the literature, some works propose methodologies to choose the appropriate artificial lift method. Some of them offer an economical evaluation tool; but a methodology that includes the subsea ESP as an option for heavy oil deep water projects was not found in the literature. This paper proposes a methodology that can be easily applied with the software's commonly used in the industry, therefore adding information to the existing body of literature that can benefit practicing engineers.
Collaborative Bit and Reamer Design Solution for Performance Drilling in Salt and High Durability in Challenging Subsalt Interval in One Run, Deepwater Gulf of Mexico
Authors: Havard Katherine , Durairajan Bala , Stith Steven , Goyal Sanjay , Trunk Philip , Nagaraj Mahavir , Trahan Dexter , Descamps Guillaume , Dykstra Mark , Louback Leonardo , Norvell Marcus , Pinard Christopher , Zhang Youdan , Rabei Rob , Halpin Matthew
Published: October 2019

This case study highlights the challenge of identifying the root cause of bit failures and provides an iterative design solution for maximizing drilling performance on a deepwater Gulf of Mexico (GoM) field development project. The well design and project economics required drilling through two distinct lithologies: salt followed by subsalt sediments consisting of plastic shale, abrasive sands, and marl. The operator wanted to drill through these in the same interval, in one run, while simultaneously achieving high rates of penetration (ROP) and maintaining durability for the entire interval.

Offset wells from previous operations in the area provided an initial starting point for the design, despite being quite different from the new well plan. A new drill bit and reamer combination were developed and built for the first well. In addition, the bottomhole assembly (BHA) design was optimized and detailed drilling parameter roadmaps were provided for the field crew. When the first run resulted in a premature bit failure, an in-depth post-run analysis was completed. A rapid response root-cause analysis was conducted, which resulted in a new bit design and expedited manufacturing to deliver the new bit within the tight timeline between consecutive wells.

Historical data from the Exploration &Appraisal (E&A) wells in the field indicated coring as the prevalent form of bit failure in the subsalt interval and loosely correlated with drilling of a middle Miocene sandstone. However, the wide range of bit vendors, bit sizes, and dull conditions in the data created uncertainty on root cause of failure. Although a good ROP was achieved in the salt section on the first field development well, the bit suffered premature wear in the subsalt interval, resulting in two additional trips to drill the interval. Each worn bit was thoroughly analyzed in conjunction with the drilling parameters and mud logging data from each bit run. Against the previous assumption of coring being a result of drilling abrasive sandstones, it was now determined that the failure mechanism was most likely a result of drilling shales with high bottomhole pressure causing plastic behavior, regrinding of cuttings at the bit face, and insufficient cuttings evacuation. An entirely new bit design was generated to prevent this failure mode and manufactured in time for the next well. The new bit design combined with revised drilling parameters strategy resulted in the most successful run ever in the field: 10,854 ft drilled (7,000 ft of reaming) in one run at high ROP in the salt followed by good ROP and excellent durability in subsalt formations.
Visualization of Ensembles of Oil Reservoir Models Based on Pixelization, Small Multiples and Reservoir Similarities
Authors: Silva Celmar Guimarães da , Santos Antonio Alberto Souza , Schiozer Denis José
Published: October 2019

Providing an overview of an ensemble of oil reservoir models could help users compare and analyze their characteristics. Approaches that show a single model at a time may hamper analysts’ understanding of the whole model set. In this paper, we propose two visualization approaches that show multiple reservoir models, simultaneously and on a single screen, with the goal of helping users to compare models and improve their understanding of ensemble characteristics. First, we calculate 2D models from the ensemble's 3D models. We then create two visualizations that represent ensembles of these 2D models. The Small Multiples approach lays out heatmaps of 2D models side-by-side on a grid. Pixelization approach shows n 2D models in a single heatmap, where each cell (i, j) contains n subcells that represent values in the coordinate (i, j) of each model. Both approaches display their elements (heatmaps and subcells) clustered by X-means, which may help analysts identify similarities and representative models in the ensemble. We used two types of distance matrices: based on Euclidean distance of models for a given property or, based on Euclidean distance of feature vectors of the 2D models. We tested our approaches within models based on Brazilian benchmark cases corresponding to a turbiditic reservoir (UNISIM-I-D/M/H) and a presalt carbonatic reservoir (UNISIM-II-D). As a result, the Small Multiples approach presented clusters of similar models for some properties of the ensembles we studied, e.g. eight clusters of porosity values in UNISIM-II-D's ensemble. This fact suggests that eight representative models can represent the ensemble, regarding porosity. Also, a Pixelization approach revealed patterns that happen in specific regions of all models of an ensemble, such as an abrupt change of porosity values in the northwest region of UNISIM-I-M's models. Both approaches have the potential to help analysts perceive situations that would be improbable to observe in a graph with only mean values for each cell. Therefore, our proposal can be helpful to users who need to deal with uncertainties and have an overview of ensembles of models for better understanding and decisionmaking, e.g. when they need to choose representative models for a process of decision analysis related to petroleum field development and management.
1st Development of Advanced Purification of Produced Water Technology at Greater Sirikit Oil Field by Dissolved Gas Flotation Technique
Authors: Lertrojanachusit Nattapong , Thunmasarnrit Urisa , Techasuwanna Ratipat , Linjongsubongkoch Phansak , Sa-Nguanwong Ittiwat , Kiravanich Parntip , Metheethara Pongsak , Umpuch Saran
Published: October 2019

The production of S1 Greater Sirikit Oil Field production primarily contributes from waterflooding operation, where water is reinjected into reservoir to increase reservoir pressure and sweep movable oil to adjacent production wells. Estimated oil gain from waterflooding is expected to be 34 MMSTB with upside volume of 19 MMSTB. One of the complexities of waterflood operation is water qualities. As High solid particles and oil content presenting in injected water leads to reservoir plugging indicating by an increase in injection pressure and reduction in injection rate. With 53% of total water injection wells show signs of plugging, water quality improvement is one of the major projects initiated by S1 asset to tackle the problem.

Inadequate produced water treatment results in excessive solid particle and oil in water content. Eventually, it will effect on waterflooding and EOR performance. To maintain production, it is required to improve quality of water treatment in order to sustain oil gain. The gas flotation is one of promising technology and practically established methods to enhance separation of oil substances and particulates from water when simple gravity separation is not sufficient to reach the desired concentration.

In this project, the most challenged of this project are of necessity of Outlet TSS Concentration below < 20 and 80% removal particle size > 5 microns and Oil Outlet concentration below 25 ppm, whilst the TSS and oil inlet are approximate 200 ppm. The conventional flotation technologies consists with two main systems as detailed below. (1) Induced Gas Flotation Technology (IGF), (2) Dissolved Gas Flotation Technology (DGF). The difference between DGF and IGF is the bubbles size generation. Typically, the IGF unit produces bubble sizes ranges more than 100 microns, whilst the DGF unit creates bubble sizes below 100 micron.

Engineering team sought for appropriate technologies by reviewing COMPANY's past projects as well as screening the commercial channels. Apart from that, team amalgamated with Chulalongkorn University to gain academic point of view and perform JAR test to confidentially ensure Licensor's Technologies. Several factors shall be controlled and optimized to accomplish the performance guarantee via consideration of Flotation technique (DGF and IGF), Retention Time, Bubble Size, Coagulant & Flocculants Chemical properties, Chemical Compatibilities, Operating Condition Control (Pressure, pH).

In addition, the selected vendor executes engineering design and construction to deliver superior water quailities. Starting DGF unit to conduct performance test run, DGF unit captivately devises positive outcome of water treatment and demonstates high accuracy and reliable with corresponded correlation model when feed condition changes.
FPSO Hull Brackets Repair by Cold Bonded Reinforcements - Project Lessons Learnt from a World First Offshore West Africa
Authors: Paillusseau Christophe , Errotabehere Xabier , Florio Vito , Bulboaca Marcel , Pinto Guilherme , Galter Andrea
Published: October 2019

An increasing number of Brazilian floating platform units are currently entering a mature age inducing numerous asset integrity issues. As corrosion damages FPSOs’ hull structures, costly structural maintenance operations in extreme marine conditions are sometimes necessary. Crop and renew are very labor-intensive operations and usually require dry docking vessels. The nature of an FPSO operation practically demands it stays offshore, which raises several operational, safety and financial challenges. Indeed, dealing with flammable substances means that the use of conventional hot works techniques, such as welding or grinding, involves many critical safety assessments and/or production shutdowns. Thus, the challenge would be to carry out these repairs offshore while guaranteeing high safety standards and avoiding production shutdowns. FPSO operators, like SBM Offshore, have therefore been looking for a while for "cold work" in-situ solutions that guarantee safe and economical hull repair.

This paper will describe how SBM Offshore streamlined a world first implementation of a disruptive innovation (from TRL 5 to TRL 7 as per API) within less than a year through a partnership with COLD PAD, an industrial start-up of only 3 people at the time it was first proposed. It covers risk assessments, expert analysis, and overall qualification process.

It will also detail how Classification society was involved as well as typical lessons learnt from the project execution with a focus on the offshore campaign which took less than two weeks. Finally, the paper will provide indications on the advantages such a solution generates for FPSO hull asset integrity in terms of safety, planning, economics (reduced total cost of ownership) and how it can be extrapolated to lower OPEX for deepwater ageing FPSOs.

The business case considers an FPSO located in deepwater West Africa where, in 2016, SBM Offshore identified a set of corroded brackets in a void tank located close to two crude oil tanks. Classification Society imposed steel renewal for 4 of these brackets. After engineering assessment, it was concluded that conventional hot works would yield to a highly detrimental production disruption. At the same time, COLD PAD was finalizing the co-development with TOTAL and IFP Energies Nouvelles of an innovative alternative to "crop and renew" for structural reinforcement. ColdShield™ is specifically dedicated for the on-site maintenance of FPSO hulls without the need for hot works, thus avoiding production disruption for several scenarios. This original repair technique obtained a class approval with an anticipated service life of more than 10 years based on an established methodology of bonded composite reinforcement, used in other industries such as aerospace.
Improving Recovery Factor in Campos Basin
Authors: Ferreira da Silva Patricia , Moreira Branco Celso Cesar , Bampi Dirceu , Echenique Silveira Gustavo , Pereira Nunes Fabiano , Faerstein Marcos , Garcia Cordeiro Tessarolli Fernanda
Published: October 2019

This paper describes recent efforts into continually increasing the recovery factors in the Campos Basin reservoirs, which translate in significant investments foreseen for the next years to increase the production and recovery of the Basin. Some strategic efforts comprise measurement and critical analysis of current recovery factor, evaluation of recovery potential per reservoir and the creation of initiatives focused on the main technical requisites that would allow higher recoveries.

Campos Basin complexity, along with the maturity of the existing infrastructure, brings new challenges to the continuity of production. Among those challenges are the capacity to process large amounts of produced water and the demand for revitalization of production facilities, including topside, subsea and new wells.

Despite excellent results achieved in pre-salt reservoirs in Santos Basin in the recent years, Campos Basin remains an important province for Brazil's oil production. Still responding for 40% of the current production of oil in Brazil, the basin presents a promising future in the next decades. Revitalization projects, development of recent pre-salt discoveries and concession contract extensions are among the ongoing efforts towards Campos Basin renewal.

Along with operations and complementary projects, a strategic program called RF Ambition was set up in 2019, aiming to: deepen the diagnosis of the recovery factor per reservoir;establish recovery targets and ambitions for each reservoir;identify initiatives to boost recovery;provide the technical support to deploy the projects with potential to allow achieving the targets and ambitions in Brazilian fields.

An accurate diagnosis of the basin's recovery factor relies on a careful and thorough detailing of its reservoirs. Campos Basin has hundreds of production zones with different lithologies, in place volumes, types of fluids, geological complexities and water depth. Data analysis, evaluation and comparison to analytical estimates and international benchmarks can minimize the risk of reaching superficial or even incorrect conclusions.

The remaining potential of the reservoirs, approached by the identification of opportunities, translates into mid- and long-term supplementary projects to exploit undeveloped zones and optimize the recovery of the reservoirs, thus increasing overall recovery of the fields in Campos Basin. The aggregated contribution of these new opportunities integrates an ambitious target of recovery factor for the basin.

There are significant opportunities to increase Campos Basin's recovery factor and, to achieve the forecasted targets, technical and economic challenges must be overcome with the contributions of all agents involved in the upstream chain.
Reduction of CAPEX & Optimization of OPEX with Innovative Ideas by Integration with Brown Field and Green Field Development to Achieve Zero Venting
Authors: Sunnapu Ravi Kanth , Awang Ahmad Anas
Published: October 2019

Baronia field is located in Sarawak Operations, Miri and started production in the year 1973. It consists of two process complexes BN–A and BN–B. Each of these complexes has its own satellite vent platform which are BNV-A and BNV-B.

In line with PETRONAS statement of purpose ‘A Progressive Energy and Solutions Partner Enriching Lives for a Sustainable Future’, the operators had initiated to adapt sustainability as a key element in PETRONAS operations. Aligned with BDO EOR PSC venting/flaring reduction roadmap, in 2010, SKO Reliability and Integrity Team were driving two vent to flare conversion project (BNV-A and BNV-B) to be incorporated. The BNV-A vent to flare conversion project was completed at a cost of USD 9.6 million. The high cost has raised concerns to the BNV-B vent to flare conversion project as it was considered a major investment with no expected economic revenue returns.

A new project, BARDEGG-2/BN EOR, came up to develop a new Central Processing Platform (BNCPP-B) bridge linked to existing facilities (BNG-B), for processing of new Non Associated Gas (NAG) fields & EOR. BNCPP-B is designed with its own flaring system for the new facilities. The green field project team prefer not to touch any existing brown field scope to avoid complications.

In view of this matter, SKO Operations Readiness & Strategic Assurance team (ORSA) has been able to come up with a brilliant idea of achieving zero continuous venting and cost optimization. The proposed innovative design is exclusively from SKO ORSA team and was supported by SKO Management.

In this paper we will demonstrate the innovative approached by operators in order to achieve zero continuous flaring/venting in Baronia offshore field. The results and observations post the realization of design will also be discussed. The impact has been huge in terms of enhanced production continuity and plant reliability, maximized environmental sustainability by reduction of greenhouse gas emissions, and major cost savings.
On the Shared-Actuation Control for the Operation of Manifolds in Subsea Production Systems
Authors: Rabello Alexandre , Neto Dorival Natal , Coelho Eduardo José de Jesus , Seraco Estevan Pereira , Destro Wagner
Published: October 2019

This article presents a set of analysis and results on Shared-Actuation Control (SAC) techniques, intended for the remote control of valves in subsea manifolds. The discussion covers historical aspects, including presentation of real cases of SAC in Brazilian fields of Petrobras, as well as covers a conceptualization for the technique. The formulated concepts are used indeed to derive a methodology, intended to guide the development of SAC schemes, during engineering projects of subsea manifolds.

The discussion is based in part on the unique experience accumulated by Petrobras in the last 20 years, with the development and introduction of a SAC-based subsea manifold in Campos Basin, Brazil, and the latest development efforts ongoing by 2019 for a new generation of SAC, for the application in subsea manifolds to be installed in ultra-deep waters of Pre-Salt fields, in Santos Basin, Brazil.

The methodology proposed in this article is based on a comparative approach which aims to incorporate, on design of SAC, the best engineering practices and lessons learned from traditional Electric-Hydraulic Multiplexed Control Systems (EHMCSs). We refer to such approach as the Inheritance & Counterbalance (I&C) Methodology, since it is based on the application of two specific principles, namely, the Inheritance and Counterbalance Principles. The principles are proposed in this article as well. Taking as starting point a set of technical characteristics of EHMCSs, such as employment of redundant subsea electronics and methods of subsea installation, a subsea engineer can apply the I&C Principles to determine if SAC should inherit a given EHMCS characteristic or, if inheritance is not feasible for some reason, adopt alternative requisites on SAC, in order to counterbalance the effects of such no inheritance.

The conceptualization of the I&C Methodology allow us effectively applying it, to obtain as result a table of engineering requisites, suitable for SAC schemes destined to subsea manifolds. The proposed table is presented in this article and incorporates several engineering aspects, which are arbitrated from the knowledge on previous applications of Petrobras in subsea control systems. Such applications include both SAC schemes and EHMCSs, featured on fields of Campos and Santos Basins.
Mid-Scale FLNG Production Unit for Marginal Fields
Authors: Tierling Kenneth Shane , Mahdavian Mohammad
Published: October 2019

The scale and productive life of associated gas from subsalt production and small offshore gas reservoirs in remote areas, has made economic justification difficult for dedicated onshore processing facilities with associated subsea pipelines. Floating LNG (FLNG) offer freedom from the subsea pipeline, but the biggest have been designed for specific large fields.

Another approach is to build flexibility into the design of the FLNG facility, potentially increasing the initial CAPEX of the unit, instead of targeting a specific field. This approach allows the CAPEX to be amortized across multiple offshore fields, avoiding a stranded investment.

This paper addresses topsides where flexibility in topsides processing units is advantageous for pursuit of multiple marginal fields over the life of the FLNG asset, focusing on the 4.5 to 9 MSm3/day (160 to 330 MMSCFD) of natural gas liquefied to 1 to 2 million tonnes per annum of LNG.

Standardizing modular designs for FLNG processing units, provides opportunities to build or retrofit the FLNG facility in smaller yards and can reduce project schedule and costs associated with the design and construction of the FLNG facility. Considering future relocation of the floating unit to other fields, requires some flexibility in the initial design to reduce future changes, without negatively impacting first field performance.

Using this approach, producing gas from marginal offshore fields could be a viable option by utilizing small or mid-scale FLNG to liquefy gas, using one facility to liquefy serially multiple marginal fields.
Brazilian Regulatory Framework: From the Past to the Expectations About the Future
Authors: Bastos Marcelo Amorim , Bastos Jorge Luiz
Published: October 2019

Brazil is one of the most prominent oil and gas offshore market. Recently, investors’ interest has increased, but not only because of the oil price recovery and pre-salt discoveries, but maybe also because of important changes in the regulatory side. Several issues have been discussed by authorities with the industry: local content flexibilization, unitization agreements, multiple fiscal regimes (PSA, Concessions, and Transfer of Rights Agreements), Repetro customs regime, decommissioning regulations, among other topics. To understand this environment is important to look at the changes and the history since the beginning, besides the economic and political forces which influence the decisions. In addition, Brazil 2018 elections have changed the direction and perspectives for this important economic sector. In this paper, the authors describe the evolution of the regulation, the contract models and results of bid rounds in order to tracking the effects of the past decisions. It can help to find clues about which should be the next steps in terms of new regulations for the Brazilian market.
Successful Offshore Coiled-Tubing Permanent Well-Abandonment Operation Uses Downhole Real-Time Parameters to Set Inflatable Packers with Surgical Precision in Cost-Effective Manner
Authors: Guimaraes Cassiano , Delgado Eduardo , Galvao Lucio , Frotte Adriano , Gouveia Manoel , Borges Carlos
Published: October 2019

The systematic approach adopted by a service company and a Brazilian National Oil Company (NOC) to achieve the goal of safely abandoning wells with different completion types using light workover vessels is discussed. Having determined the abandonment methodology, the service company personnel developed processes and procedures to reach the objective. These include advances in coiled tubing (CT) rigup procedures and using a real-time telemetry system. This approach facilitated the timely and cost effective abandonment of more than 15 wells since 2017 in a safe and environmentally acceptable manner.
Brazil Oil and Gas Sector Piece De Resistance: The Pre-Salt Play Developments
Authors: De Jesus Delgado Fernanda , Neves Goncalves Pedro Henrique , Chambriard Magda
Published: October 2019

The magnitude of the pre-salt projects, most located in Brazil ultra-deep waters, coupled with the enormous potential already auctioned, leads to the following questions: what will be Brazil's share in the world's deep-water development? How should suppliers prepare themselves to assist Brazil in the task of making these opportunities viable?

Since 2013, the country awarded over R$ 43 billion in signing bonuses. Despite the pessimism associated to the oil price drop in 2014, Brazil has gone forward with the development of pre-salt areas and the resume of the bidding rounds, reaching the top 10th position in world's biggest oil producers (BP 2019).

This paper forecasts the oil potential for these areas, as well as the Brazilian oil production for the next 15 years and the demand for facilities to reach that potential. Those forecasts clarify the increasing importance of Brazilian deep-water oil in the global scenario.
Partnerships & Joint Ventures in Brazilian Oil and Gas Markets
Authors: Bastos Marcelo Amorim , Bucheb José Alberto
Published: October 2019

Partnerships and JV are quite common in the Oil and Gas industry. In the offshore activity, in order to reduce the risks of capital intensive projects oil companies used cooperate entering into JV agreements. In addition, local content requirements and entry barriers in new markets, are some reasons to create partnerships between international and domestic companies. Brazil is not different. It is a market that has some challenges in which the cooperation with a local partner could reduce the risks for a foreign investor. In the oil companies’ side, Petrobras is the target partner for an international oil company, because of its technical reputation and successful implementation of ultra-deep operations. In other segments, Petrobras, can be the main client, sole supplier or big competitor. Petrobras is subject also to laws and regulations to hire contractors, there are local content requirements regulations, industry-specific tax, fiscal and customs regimes, among other risks and opportunities in which the cooperation with a domestic company could help to solve in a more efficient way. The author of this paper describes the advantages of the partnership for international and domestic companies which want to invest in Brazil in the several perspectives along the oil and gas supply chain.
A Case Study in Production Enhancement Through Installation of Optimum Artificial Lift Technology
Authors: Kumar Sandeep , Ali Sharafat , Kalwar Shuaib Ahmed
Published: October 2019

The well, Halini X1, was initially tested at an average rate of 1,750 BOPD, with 26-degree API gravity and produced gas at 1.27 MMscfd. The production history showed that the well head parameters were at continous decline due to natural depletion of reservoir. Based on the observation, a complete nodal analysis of multiphase flow was conducted. The results indicated that the natural flow of well will cease when the reservoir pressure decline below 3,000 psig. Therefore, a suitable artificial lift was selected and designed to improve the vertical lift performance of well, making the production sustainbale even at low reservoir pressures.

The high gas content of the reservoir fluid, deep reservoir zone, and adequate bottom hole pressure of Halini X1 favored gas lift to be more viable compared to other ALS methods both technically and economically. The results of the gas lift simulation showed enhancment in production; however by changing the tubing size from 3-1/2 inch to 4-1/2 inch further magnified the performance of gas lift injection in terms of production.

Based on design, gas lift equipment was installed through workover and the well was put on gas lift injection. The detailed comparison was drawn between natural flow and the flow on gas lift. The outcomes were found with remarkable increase in the life span of well over natural flowing period and led to higher recovery of production.
Statistical Analysis of Split Switchboard Operation in Dynamic Positioning Drilling Units
Authors: Passos Ramalhete Marina
Published: October 2019

As the Industry of Oil and Gas advanced in deeper waters exploring, the drilling units positioning technique alternated from anchors to dynamic positioning (DP). Nowadays, even in deep or shallow waters, a large number of DP drilling units has been used. In addition, it was noticed that technology has been improved and was incresead redundancy and hardware in diferentes subsytems of the vessels. No matter how many redundancys a DP drillship contractor can provide to his own vessel, the faults, in the system and subsystem, have been experienced over the years, either for equipment failure or for human errors, and also could lead a of positioning and disconnect from the well.

Taking a deeper look into all DP Petrobras incidents experienced, it was observed that the most of them are related to power system in many differents types of failure. As of knowlodge, there are two main types of switchboards mode: single busbar and split busbar, each of them has yours own vantages and disvantages, but based in its past experienced, few years ago, Petrobras strongly recommended to all its drilling contractors to operate in split busbar instead of a single busbar mode, in order to prevent major failures.

Once that most part of the DP drilling units operating in split switchboards, the worst case failure experienced in the power system, is a partial blackout, but others could be linked a DP incidents. The events assessed, from the Petrobras database DP only, showed that human failures and faults arising from maintenance processes in critical equipment are, currently, the major factors causing DP incidents. Considering the faults occurred, they, usually, do not result in major events, such drift-off and emergency disconnect from the well. In fact, a partial blackout itself does not even lead to a yellow alarm, by Petrobras definitions; even though, knowing the main type and root cause of the failures will help to prevent similar events.

Keeping in mind how importante is to find the root cause of all incidentes, associanting it to a systematic collection and analysis of numerical data helps to investigate the relationships among incidents and to explain and control their occurrence. In other words, a statistical analysis gives a full picture of all incidents and recurrences, also provides substantial informations to estabilished proper barriers to avoid similar ocrurrences; and, especially, when is talking about switchboards modes, adds another decision parameter in the choice which is better.

This is paper will present a statistical analysis of the failures occurred and non productive time during operation in split busbar due to dynamic positioning incidents related to power system failures. Evaluate and compares performance over time of semi-submersible and drillship rigs.