Taking advantage of the analogy between hydraulic and electrical flows to facilitate the prediction of porous media characteristics is a longstanding practice in petroleum engineering. The relationship between hydraulic and electrical properties is widely used in well-logs interpretation and characterization of transport properties of porous media relying on the strong correlation between electric and hydraulic flow conductance. However, due to the lack of direct investigations, the similarity among their pathways/tortuosities is still unclear. It is a challenging and almost impractical task to identify the streamlines experimentally. Here a series of direct finite element numerical simulations are conducted within pore-level microstructures to extract and compare the streamlines of both electric and fluid flow currents and examine the accuracy of the analogy by predicting the petrophysical characteristics of the case studies. The fluid flow and electric transports are simulated through pore-level digital rocks of synthetic unconsolidated sand packs representing the Athabasca oil sands deposit as the second largest oil reserve in the world. The formation factor, porosity, and absolute permeability of the media under consideration are predicted, and consequently, the streamlines of both electric and hydraulic currents are extracted and compared in terms of length, shape, and pathways. According to the results, the fluid flow pathways pose differently and are longer than the homogeneous electric current streamlines. The ratio between the hydraulic and electric tortuosities follows a polynomial trendline, and a local extremum occurs at the porosity of eighteen percent. Pedotransfer functions for tortuosities, dimensionless permeability, and formation factor are proposed underpinning the rigorous relationships between transport processes in rocks.
Jin, Fu (CNPC Research Institute of Petroleum Exploration and Development & CNPC Drilling Research Institute) | Xi, Wang (CNPC Research Institute of Petroleum Exploration and Development & CNPC Drilling Research Institute) | Shunyuan, Zhang (CNPC Drilling Research Institute)
Located in south of Eastern Venezuela Basin, Orinoco Oilfield is the unique huge ultra-tight oilfield that has not been developed by scale in the world. The high-density tight oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. ML Block whose OOIP is 178*108bbl is situated in east of the oilfield, while cluster horizontal well drilling and cold production technologies are still under research there.
Based on precise geological researches numerical simulation was carried out to optimize cold production of ultra-tight oil with foamy oil flow patterns in horizontal wells, including optimization of well placement, well spacing and horizontal section length. The near-bit geo-steering drilling technology was applied on adjacent wells to test its performance, while an experiment was conducted with PVT apparatuses to examine the effect of pressure decline rates on foamy oil flow. A long core pressure depletion test was accomplished to reveal the effect of foamy oil flow on recovery factors.
Three-dimension cluster horizontal well drilling and completion technologies shall be applied to develop ultra-tight oil reservoirs in huge loose sandstones, with the near-bit geo-steering drilling technology that controls landing points and horizontal sections in real time, keeping the bit move ahead along the lower boundary of the reservoir. Therefore, recovery rates may be dramatically improved due to the gravity drainage of ultra-tight oil. The most appropriate spacing of horizontal wells (500-600m) and horizontal section length (800-1200m) were determined to achieve the maximum recovery rate. The experiment proves that the recovery rate improves as the formation permeability increases, which means the "worm hole" contributes to heavy oil extraction. Boreholes with relatively large diameters, extensive perforated holes and slotted liners may be used to complete wells. In order to take the most advantages of the foamy oil flow mechanism high displacement ESPs shall be used with the selected thinner squeezed at the bottom, otherwise PC pumps with the thinner added at the wellhead are recommended.
Cold production technologies applied in ML Block save the overall production cost by 15.2%, improving the ultimate recovery rate by 8.6%. The foamy oil flow theory is improved, while it is the first time to integrate foamy oil flow production technologies with cluster horizontal well drilling technologies and near-bit geo-steering drilling technologies. As a result, the overall production rate of tight oil was greatly improved and the average production life of wells was extended.
The Brazilian pre-salt operation presents many technological challenges. Among the key aspects for a successful operation, the choice of drilling fluid is important to avoid structural problems and predict the final well caliper. Drilling operation simulations can be used to indicate operational conditions and assist the choice of the drilling fluid. A simulator has been developed to represent drilling, circulation and static operations involving well drilling processes considering simultaneous effects of solubility and salt creep. The main objective is to avoid wellbore enlargement due to salt solubility in water-based fluids. A bad fluid choice can lead to column imprisonment or a wellbore caliper increase; both effects could compromise the well structure and add difficulties and costs in drillings operations. The model implemented is based in salt transport equations and mass transfer adjusted correlations. The common ion effect is considered in presence of more than one salt. Initial development did not include salt creep and influence of drill cuttings size. The present work adds these effects and evaluates their influence in the final caliper. The salt creep effect is computed as a decrement in well radius, which is obtained in a deformation rate table as a function of fluid density and depth. The authors propose an analysis of salt creep effect and drill size cuttings in a real case study. The need for new adjustments in mass transfering correlations in the solubilization modelling is evaluated and its impacts are presented. The change in the well geometry during drilling, due to solubilization and creep of the salt formations is computed in a dynamic mesh. The application estimates a final wellbore caliper after a sequence of operations in a drilling phase. Such estimate provides arguments for an optimized drilling fluid selection. This work contributes to improve salt drilling operations, avoiding well losses and reducing drilling time and cost.
Cold water injection creates a cooled rock region around the well that can reduce the horizontal stresses acting on the reservoir and, also, the injection pressure to initiate and propagate a fracture. However, the impact of thermal stresses in saline caprocks, where creeping occurs, is not well understood yet. This study aims at modeling the cooled region created by cold water injection and evaluate the thermally induced stresses in both reservoir and saline caprock.
In order to assess the evolution of the pressure and temperature in the reservoir and in the caprock during 16 years of cold water injection, reservoir simulations considering thermal effects were carried out. Various simulations were performed using different water injection rates and different thermal diffusivities for the reservoir and for the caprock. The model used in these thermal simulations comprehended not only the pre-salt carbonate reservoir, but also the salt rocks. Stress and strain were evaluated using a 3D finite element in a one-way coupling scheme, including the reservoir, overburden (salt and post-salt), sideburden and underburden.
In the worst simulated case, after 16 years of cold water injection, the height of the cooled region in the salt was about 200 m above the top of the reservoir. As expected, horizontal stresses in the reservoir significantly decreased with cooling. On the other hand, horizontal stresses in the saline caprock did not change significantly, even though the thermal expansion coefficient of salt rocks is five times greater than that of carbonates. This result suggests that creeping in the salt relieves thermal stress induced by cooling. Thus, saline caprock integrity is not influenced by cold fluid injection in the reservoir, as long as salt creeping can be considered.
Although cold fluid injection may cool the salt, stress state in the caprock remains unaltered. Thermal stress is relieved by the salt creeping at the expense of plastic deformations. Thus, the saline caprock integrity is not impacted by cold fluid injection.
The increasing demand to plug & abandon (P&A) subsea wells has reinforced the need to identify true opportunities to reduce the costs of subsea abandonment.
The existing method in typical P&A programs of switching from a light well intervention vessel (LWIV or dedicated intervention semi-submersible) after lower abandonment, to a drilling rig with subsea BOP and drilling riser to perform upper abandonment activities is uneconomical, due the loss of efficiency and increase of total operational time.
In 2016, a project to develop an 18 ¾" large bore Riserless Open-Water Abandonment Module (ROAM) was launched to enhance well abandonment capacity from a well intervention vessel, by allowing tubing to be pulled in open water in a safe and environmentally contained manner. The ROAM is run in combination with a high pressure Intervention Riser System (IRS)
As ROAM has circulation capability and is self-contained, once the tubing hanger is unseated, residual fluids and debris can be flowed back through circulation hoses and the IRS intervention riser system to the LWIV, guaranteeing minimal leakage to the environment during tubing pulling operations.
ROAM also allows operator to check integrity of the cement bond behind the casing through a logging run after production tubing removal. According to the results, operator can decide to move on with upper cement plug placement and conclude the P&A or safely leave the well and prepare the remedial operation. The full bore access afforded by ROAM opens up multiple options for ‘abandonment in situ’ operations to be performed.
In order to keep the well safe in the event of the vessel losing its position (through drift-off or drive-off), ROAM has dual 10,000 psi rated shear-seal rams, an emergency quick disconnect (EQD) system and a stand-alone intervention work over control System (IWOCS), as well as a 10,000 ram to isolate annulus/circulation side.
ROAM, combined with existing riser-based (IRS) and riser less intervention systems (Subsea Intervention Lubricator or SIL), will extend the capability of well intervention vessels to perform a full P&A without jeopardizing well control and environmental protection.
The paper will give a detailed description of the design, capabilities and operational premises considered in ROAM development and also demonstrate how the system is deployed and operated to guarantee a safe, efficient and cost-effective operation. The paper will also detail all the executed qualifications and performed tests, as well as the update about manufacturing and field-tests.
Over the last decade, a number of subsea solutions have been deployed to unlock the commerciality of deepwater fields and increase the overall recovery factor of the reservoirs. Numerous types of monitoring and measurement technologies have been developed and installed downhole, subsea, and topside, but usually in a fragmented manner. The traditional field surveillance approach often addresses the reservoir challenges separately from issues that may affect flow in the production network or from processing facilities considerations. The value of information obtained using sensing equipment is then not fully taken advantage of, and critical information is lost due to the lack of integration. The objective of this work is to link all data collected along the fluid journey from the reservoir to the process facilties in order to optimize its production and better manage reservoir recovery.
In this work, a novel integrated production management solution (IPMS) is introduced. Dedicated subsea and subsurface metering devices, advanced flow control equipment, production surveillance systems, and production optimization tools are combined to increase the understanding of the reservoir and subsea production network, maximize the value of the subsea hardware and address operational challenges to enable increased predictive flow assurance capabilities and production optimization. Bridging the gap from abstract measurement values to production management decisions, such as inflow control actuation; allow a better reservoir management implementation along of the field life, leading to an increased recovery.
The functionality of the system is designed to address a number of challenges, including the following: reservoir management—recovery increase by combining continuous downhole sensing, seabed data, and IPMS Equipement centric monitoring and predictive maitenance thermal management—increase in system no-touch time and improved system preservation hydrate management—opex savings in regards to hydrate inhibitor injection and regeneration liquid management—avoiding unexpected shutdowns due to liquid surges pigging optimization—potential for reduced production losses during pigging operation and reduced pigging frequency low temperature management—material integrity and hydrate prevention corrosion and scale inhibition optimization—completion, subsea production system (SPS), and pipeline integrity erosion monitoring—SPSs and pipeline integrity.
reservoir management—recovery increase by combining continuous downhole sensing, seabed data, and IPMS
Equipement centric monitoring and predictive maitenance
thermal management—increase in system no-touch time and improved system preservation
hydrate management—opex savings in regards to hydrate inhibitor injection and regeneration
liquid management—avoiding unexpected shutdowns due to liquid surges
pigging optimization—potential for reduced production losses during pigging operation and reduced pigging frequency
low temperature management—material integrity and hydrate prevention
corrosion and scale inhibition optimization—completion, subsea production system (SPS), and pipeline integrity
erosion monitoring—SPSs and pipeline integrity.
For the first time, integrated production data are used in online pore-to-process integrated models to guide reservoir decisions, optimize opex, and enhance recovery. Specific examples such as detection of reservoir property changes and their impact on recovery, optimized inorganic scale, and hydrates management based on integrated downhole seabed and process data are discussed in detail.
Ensemble data assimilation methods have been applied with remarkable success in several real-life history-matching problems. However, because these methods rely on Gaussian assumptions, their performance is severely degraded when the prior geology is described in terms of complex facies distributions. This fact motivated an intense investigation reported in the literature to develop efficient and robust parameterizations. Despite the large number of publications, preserving plausible geological features when updating facies models is still one of the main challenges with ensemble-based history matching.
This work reports our initial results towards the development of a robust parameterization based on Deep Learning (DL) for proper history matching of facies models with ensemble methods. The process begins with a set of prior facies realizations, which are used for training a DL network. DL identifies the main features of the facies images, allowing the construction of a reduced parameterization of the models. This parameterization is transformed to follow a Gaussian distribution, which is updated to account for the dynamic observed data using the method known as ensemble smoother with multiple data assimilation (ES-MDA). After each data assimilation, DL is used to reconstruct the facies models based on the initial learning. The proposed method is tested in a synthetic history-matching problem based on the well-known PUNQ-S3 case. We compare the results of the proposed method against the standard ES-MDA (with no parameterization) and another parameterization based on principal component analysis.
Flow control devices (FCD) play a vital role in an intelligent completion’s ability to enhance reservoir management capabilities by allowing the operator to control inflow and outflowremotely. Among FCDs, the most versatile type is electrohydraulic. However, because these electrohydraulic FCDs are permanently installed in severe downhole conditions, it is important to integrate the reliability qualification testing (RQT) in the overall development effort. This paper describes a novel approach to product development which integrates RQT as a key component.
RQT incorporates testing for all criteria, including function, environment, and reliability. It typically includes accelerated testing, which is performed to reduce testing time while helping ensure product reliability is verified. RQT is applied in the form of a systematic, streamlined, and concurrent verification program to help improve the reliability of the product. Design for reliability (DFR) tools, such as FMEA (failure mode and effects analysis), help identify the key failure modes and failure mechanisms (causes of failure) related to the product. It is of utmost importance to understand these failure mechanisms in detail and correlate them to the stresses applied during testing.
RQT planning uses the analyses performed during the design phase, such as FMEA, reliability predictions anddevelopmenttesting results, to highlight the risks associated with the product. And, further integrates this information to efficiently design the tests. The primaryobjective of RQT is to determine whether the product will meet the mission reliability target. RQT planning not only identifies the need for component reliability testing, but also substantiates reliability targets at the component level. Multiple ingredientsare required todevelop an efficient RQT, such as (a) performing risk-mitigation studies during design phase, (b) defining a mission reliability target at the system and component level, (c) addressing the range of environmental conditions, (d) using accelerated test plans, (e) optimizing test parameters, sample size, test time, etc.
This paper presents an efficient RQT plan, developed for FCD, as well as all associated accelerated testing models for system reliability predictionsand statistical confidence. Also discussed is a uniqueapproach for identifying and integrating key elements of a holistic RQT, which can be used to design an efficient test plan. This approach unites the reliability studies performed during development stages, and further, uses accelerated testing for successful product development, resulting in both cost and time-to-market improvements.
Sensors are becoming increasingly ubiquitous in the oil and gas industry to enhance efficiency in exploration and production (E&P), as well as to improve safety and minimize the impact of these operations on the environment. In particular, knowledge of the properties of fluids contained in a hydrocarbon reservoir helps to identify the fluid type, estimate reserves, assess hydrocarbon value and optimize production. Although measurement of fluid properties can be done at the rig surface or downhole, the latter is preferred because subjecting these fluids to changes in pressure and temperature compared to the downhole environment may induce irreversible changes. Moreover, in many instances, it is important to monitor the chemical composition of a fluid in real time. Dissolved H2S in reservoir fluids has a harmful impact on cost and safety operations in drilling and production. We have investigated localized surface plasmon resonance (LSPR) methodologies and fabricated sensors for measuring dissolved sulfides in liquids. The impact of the specificity of sensing materials and the design concepts were investigated. The chemical composition and morphology of the nanoparticles affect the response of the sensor, and can be used to mitigate the strong absorption in heavy crudes. The effect of temperature on the sensor response was evaluated. Sensor response was not affected below 150o F. The effect of organo-sulfur compounds on sensor response was also investigated.
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.