Previous experimental studies show that nanoparticle-stabilized supercritical CO2 foams (or, NP CO2 foams) can be applied as an alternative to surfactant foams, in order to reduce CO2 mobility in gas injection enhanced oil recovery (EOR). These nanoparticles, if chosen correctly, can be an effective foam stabilizer attached at the fluid interface in a wide range of physicochemical conditions.
By using NP CO2 foam experiments available in the literature, this study investigates the applicability of NP foams for mobility control and thus improved sweep efficiency. This study consists of two tasks: (i) presenting how a population-balance mechanistic foam model can be used to fit experimental data and determine required model parameters, and (ii) examining sweep efficiency in a condition similar to Lisama Field (a 5-spot pattern with 4 producers and 1 injector in the middle), by using relevant gas mobility reduction factors derived from mechanistic modeling technique. The field-scale simulations are conducted with CMG software, contrasting NP and surfactant foams (in both dry and wet foam injection conditions) to gas only injection and gas-water coinjection (no foam).
The results show how the model can successfully reproduce coreflood experimental data, creating three different foam states (weak-foam, strong-foam and intermediate states) and two steady-state strong-foam regimes (high-quality and low-quality regimes). When the gas mobility reduction factors ranging up to 10 from the model fit are applied in the field-scale simulations, the use of nanoparticles improves oil recovery compared to gas-water co-injection, but not as efficient as successful surfactant foam injection does. This implies that although nanoparticle-stabilized foams do provide some benefits, there still seems some room to improve stability and strength of resulting foams.
Deep formation damage caused by killing fluid frequently occurs in blowout wells and clean-up operations may result in early water breakthrough and less hydrocarbon recovery. This paper presents three innovative practices applied in oil and gas wells that suffered blowout accidents for more hydrocarbon recovery. i.e.:
These methods have been successfully utilized in more than 40 wells for over 50 years. The three typical field examples are illustrated. One of them is an oil well in sandstone reservoir, with double oil rate as the nearby wells. The rest are a gas well in massive carbonate pool with bottom water, with the most prolific gas production in the field, and a gas well in a naturally fractured reservoir, with Gp of over 180 BCF.
Each year tens of thousands of oil and gas wells are successfully drilled worldwide. The overall safety record of the drilling and workover operations is quite satisfactory. On occasion, however, blowout problems can arise during drilling and workover where the control of a well is lost, whenever a well begins to flow uncontrollably.
The upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach hinders effective reservoir simulation and optimization of heavy-oil recoveries by use of waterflood, polymer flood, and other chemical floods, which are inherently unstable processes. The difficulty in scaling up unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.
Extensive experimental data in water-wet cores indicate that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named “viscous-finger number” in this paper), a combination of viscosity ratio, capillary number, permeability, and the cross-sectional area of the core. On the basis of the features of unstable immiscible floods, an effective-fingering model is developed in this paper. A porous-medium domain is dynamically identified as three effective regions, which are two-phase flow, oil single-phase flow, and bypassed-oil region, respectively. Flow functions are derived according to effective flows in these regions. Model parameters represent viscous-fingering strength and growth rates. The new model is capable of history matching a set of heavy-oil waterflood corefloods under different conditions. Model parameters obtained from the history match also have power-law correlations with the viscous-finger number. This model is applicable to water-wet reservoirs; it has not been tested for mixed-wet and oil-wet systems, low-interfacial-tension (IFT) environments, low permeability, and heavy-oil reservoirs with free gas cap.
In reservoir simulations, having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous-finger number. The model was first applied to a heavy-oil field case with channelized permeability by waterfloods. Simulation results with the new model indicated that viscous fingering strengthened the channeling. Also, the new model shows that a lower injection rate leads to a higher oil recovery. In contrast, oil recovery in waterflooding of viscous oils is overpredicted by classical simulation methods that do not incorporate viscous fingering properly. We further showed that coarse grid simulations with the new model were able to obtain saturation and pressure maps consistent with fine-grid simulations. The new model was then used to model a real field case in the Pelican Lake heavy-oil field. It was able to match the field-production data without major adjustment of reservoir/fluid properties from the literature, showing its competence in capturing subgrid viscous-fingering effects. Overall, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy-oil reservoirs, and hence can facilitate the optimization of heavy-oil enhanced-oil-recovery (EOR) projects.
Yang, Gao (RIPED, Petrochina) | He, Liu (RIPED, Petrochina) | Shujun, Bao (China Institute of Water Resources and Hydropower Research) | Fengshan, Wang (Daqing Oilfield Company) | Guoxing, Zheng (Daqing Oilfield Company) | lei, Zhang (Daqing Oilfield Company) | Bo, Yu (Daqing Oilfield Company) | Li, Zhang (Jidong Oilfield Company, Petrochina)
Hydrocyclone is a critical component of downhole oil-water separation technology. Sometimes, it is necessary to use two hydrocyclones in series in order to improve the effectiveness of downhole oil-water separation and reduce oil concentration in reinjected water. Unlike single-stage hydrocyclones, however, a two-stage series hydrocyclone is characterized of a more complicated flow field, more significant flow field interference and more factors that affect separation effectiveness.
The flow field of a two-stage series hydrocyclone is analyzed and, in particular, the distribution of oil phase, pressure field and velocity field near the overflow port of the second stage hydrocyclone is studied by means of a two-stage series hydrocyclone oil-water separation model built based on the hydrodynamic theory.
According to our analysis, when the water content of oil-water mixture is higher than 97%, the two-stage series hydrocyclone offers insignificant advantage in separation effectiveness compared to a single-stage counterpart; when the water content is lower than 97%, the effectiveness of separation using a two-stage series hydrocyclone is very significant, where the second stage hydrocyclone provides good repurification of underflow of the first stage hydrocyclone, helping to reduce oil concentration in reinjected water. It is also discovered that the geometry of the connector located between the two hydrocyclones is the major factor affecting the separation effectiveness of the second stage hydrocyclone. Cylindrical connector, which is identified as the best geometry by comparing connectors of three different structures through modeling analysis, can not only improve the separation effectiveness of the series hydrocyclone but also offer decreased pressure loss.
The accuracy of analysis and calculation results are further verified through comparison of results of lab tests conducted on the two-stage series hydrocyclone on the basis of analytical calculation.
In the shadow of low oil prices, it is necessary to develop economically and environmentally friendly solutions. In oil and gas industry, majority of the production stream is water. This water is produced with the hydrocarbon to surface. This requires the separation of the fluids produced and then treating those streams to abide with environmental regulations and clients' specifications. CDOWS (Centrifugal Downhole Oil Water Separator) technology is believed to provide high separation quality, high oil recovery with reduction of operating costs and less surface facilities.
The development process involves simulation of tubular centrifuge using a computational fluid dynamics (CFD) software to analyze the parameters affecting separation. After that, an experimental set up is erected which mimics in-well CDOWS. The novel design of the tool involves specially designed weir to collect the oil and water through concentric tube configuration. The parameters tested through simulation include; flow rate, RPM, tubing length, tubing diameter, API and oil/water ratios. The experimental set-up is used to confirm the sepration in the rotating tube as it is made of acrylic material.
The CFD model involves a rotating cylinder (tubing) in which oil and water are introduced from the inlet. The feed of oil and water exhibits high centrifugal forces resulting in their separation through and to the outlet of the tubing. The experimental design mimics the actual in-well design which can be implemented in a well. The design can be configured easily to change the tubing parameters.
After conducting the studies, a sensitivity analysis using design of experiment approach (DOE) and response surface plots is produced to emphasize on parameters and their interaction effects.
Findings include better separation using higher RPM, ID, L, water salinity, API. The most influential factor is RPM which can be controlled and thus will define costs for later stages of the project.
This paper presents the first work on CDOWS which is analogous to in-well configuration aiming for a solution with reduced costs.
Setiawan, Toto (PETRONAS Carigali Sdn Bhd) | Ghazali, Rohaizat B (PETRONAS Carigali Sdn Bhd) | Granados, Leidy Pitre (Schlumberger) | Chandrakalatharan, Jayasharadha (Schlumberger) | Zubbir, Ahmad Uzair (Schlumberger) | Mukrim Mohamed Hanafi, Muhammad (Schlumberger) | Sepulveda, Willem (Schlumberger)
Since 2010, Samarang Alliance, a partnership between Petronas Carigali Sdn Bhd and Schlumberger SPM, has been redeveloping the Samarang field (offshore). The objective of the Alliance is to maximize asset value through implementation of technology, processes and practices that enable infill drilling, reservoir management, EOR, Integrated Operations (IO) and production enhancement activities (PE).
Since the beginning of this partnership, the number and complexity of production enhancement initiatives via well intervention has increased greatly. As expected in an aging asset, the well integrity condition is a fundamental piece of information to achieve operational success and consequently incremental oil. The well intervention activities scope range from routing surveys to complex pumping operations.
As part of execution preparation and planning, all production enhancement initiatives (in active and/or idle wells) must have tubing and well integrity checks as early as possible. The loss of downhole tubing/well integrity is one of the biggest and most common challenges faced during the preparation and execution of the PE jobs. In those cases where there are severe tubing integrity problems, well activities can either be cancelled or classified to be performed using costly workover operation, and in the worst case overlooking those issues lead to failures in planning and execution, followed by sunk cost or losing a well.
The Samarang detection techniques portfolio currently consists of surveillance techniques such as pressure monitoring using surface and downhole pressure gauges and manual sampling with subsequent lab tests, Slickline interventions such as running Flowing Gradient Survey (FGS), Multifinger Imaging tool, Leak/Flow point tool (a combination of Pressure, Temperature and Acoustic gauges), Ponytail tool, and setting mechanical barriers (plug) with subsequent inflow tests, E-line or digital slick line conveyed Optical Cable, Wireline leak detector (WLD) and Water Flow Log, Surface testing tools such as pumping equipment to facilitate Tubing/Casing Integrity Tests.
Setiawan, Toto (PETRONAS Carigali Sdn Bhd) | Ghazali, Rohaizat B (PETRONAS Carigali Sdn Bhd) | Granados, Leidy Pitre (Schlumberger) | Sepulveda, Willem (Schlumberger) | Chandrakalatharan, Jayasharadha (Schlumberger) | Zubbir, Ahmad Uzair (Schlumberger) | Hanafi, Muhammad Mukrim Mohamed (Schlumberger) | Vaca, Juan Cortez (Schlumberger) | Yildiz, Rasim (Schlumberger)
Since 2010, Samarang Alliance, a partnership between Petronas Carigali Sdn Bhd and Schlumberger SPM, has been redeveloping the offshore Samarang oil field. The objective of the Alliance is to maximize asset value through implementation of technology, processes and practices that enable infill drilling, reservoir management, EOR, Integrated Operations (IO) and production enhancement activities.
One of the focus areas upon resource extraction initiatives of Samarang Alliance is through rigless intervention activities for production enhancement. The dynamics of Production Enhancement (PE) portfolio in Samarang requires the use of engineering and statistical tools to track their efficiency to be able to channel and strategize resources aiming for the highest return on investment (ROI).
The Samarang Well Intervention Performance Evaluation (WIPE) methodology enables the user to assess the profitability of a given well intervention activity over time. Productive layers, time and job type are plotted which helps to triangulate the best avenues for investment. Incremental production is specifically calculated for different time-lines. "Budget Cycle" (Calendar year) to evaluate the efficacy of the current year planned work budget. "PE Cycle" when referring to the duration encompassing one year (12 months) to compare similar PEs irrespective of the month of execution. "PE Life" for the entire duration that the well production will be impacted by the PE. Additionally the calculation of Unit Enhancement Cost (UEC) for the different time-lines is considered, which provides a numerical estimate of the economic value of each PE.
Superimposed with intervention history and reserve estimation, WIPE plots enables the user to find a specific profitable intervention solution to declining production. The "Opportunity Cost" can be calculated to a degree of high accuracy which supports the selection of new candidates and fulfills the requirements of a Signature Field like Samarang. Supported on available medium like Microsoft Excel, this powerful tool improves the decision making and planning processes for Brown Field redevelopment.
International and National oil companies have in their portfolios deep offshore marginal fields. Development of these fields is usually constrained by the CAPEX, OPEX, flow assurance and safety issues, which increases with maturity of the field. Subsea processing technology (SPT) is not only pivotal for unlocking such fields, but offers a novel approach that meets the challenges of developing offshore marginal fields. The present paper explores conceptual development from some of the most innovative solutions and performance analysis of the optimal SPT with field case studies demonstrated.
The paper provides a reassessment of the different SPTs available in the market as well as the limitations of such technologies. Conceptual development is carried out using a 3-step approach involving the Quality function deployment (QFD) and its tools, the Voice of customer (VOC) and Quality Matrix or House of Quality (HOQ) that analyzes and compares the capabilities of various SPTs to overcome the techno-economic challenges of marginal fields. Revalidation of results from the QFD process is done using Analytical Hierarchal process (AHP) and its pair wise comparison process, leading to the optimal innovative SPT for marginal field development. Field case analysis of this novel solution is applied to fields in the North Sea and Gulf of Guinea over an eight years period.
The present paper validates the effectiveness of SPT in tackling marginal field techno-economic challenges such as large CAPEX and OPEX, slugging, low recovery rate, remoteness of location amongst others issues. Its application in one of the fields led to increased projected revenue of up to $450,000,000 in recovery, as well as significant reduction in maintenance and work over costs. The analysis shows that SPT such as the deployment of Multiphase Pumps can be a game changer if effectively applied in marginal field development.
The paper explores the novel application of QFD and AHP to develop offshore marginal fields. These tools have been used effectively in so many fortune 500 companies, where they have led to a significant reduction in cost as well as reduction in project implementation time. Proper application of the processes described in the present paper can serve as a better alternative over the traditional field conceptual development, to maximize recovery in offshore marginal fields.
Rodríguez, E. (Schlumberger) | Jiménez, A. (Schlumberger) | Angel, J. (Schlumberger) | Bedino, H. (Schlumberger) | Scagliarini, S. (Schlumberger) | Salinas, N. (Schlumberger) | Valdiviezo, F. (Schlumberger) | Mendoza, P. (Schlumberger)
This paper describes how the creation of an innovative multidisciplinary team - the Look Ahead Team (LHT) - together with ad hoc new built processes and protocols, have greatly helped minimizing both the geological and drilling risks and their impact in the very complex wells currently being drilled in the Mesozoico, Exploration and Alliance projects in Southern Mexico (MXS). Also, it explains how the integration of different knowledge domains coupled with detailed technical scrutiny, subsurface visualization, modeling and simulation, thorough multilayers risk assessments, risk management techniques, real time data acquisition and continuous application of lessons learnt, have been delivering substantial savings to the drilling operations.
Wells can be classified as deep HP/HT and/or LP/HT wells.
The objective of the LHT is to visualize and analyze drilling related risks, to generate alerts and recommendations before a new hole section is commenced, so that undesirable and detrimental subsurface events are anticipated and prevented or minimized.
Drilling engineering, geology, geophysics, geomechanics and well placement are all represented in and form an integral part of the LHT. For each new well to be drilled, the geosciences' domain experts perform an integrated subsurface interpretation considering all current information available, offset wells and real time data.
The analysis performed is twofold: a forecast drilling scenario (well trajectory and placement) which is optimized based on the calibration attained through the iteration with existing (offset) wells using sophisticated modelling and newly created work protocols that allow effective multidisciplinary workflows, subsurface assessment and detailed risk analysis by hole section.
The main outcome of the analysis is to deliver a predictive ‘look ahead’ report which contains all risks identified at least 200 m ahead of the bit together with the risk analysis matrix and the corresponding prevention and mitigation plan. Also during the program execution, the LHT provides technical support to the engineering and operations teams anticipating the next action based on risk projection re-assessment using real data streaming.
The Look Ahead Team's newly implemented processes/workflows and innovative analysis methodologies, have been tested on 21 development wells and 3 exploratory wells for a total of 72 hole sections. In just one year from its foundation, unforeseen drilling events due to geological uncertainty were reduced by 90% achieving 10MMUSD worth of savings.
Hydraulic fracturing is the key technology in unlocking production of shale-gas wells. The production of huge amounts of pumped water affects the life of a shale-gas well; the first phase and dewatering methods have to be considered as crucial aspects of a shale-gas development. In fact, as a consequence of reservoir depletion, the gas rate decreases to a point at which the water cannot be transported out of the wellbore and starts to accumulate. Methods such as gas lift and plunger lift and the use of smaller tubing diameters, pumps, and foaming agents are commonly adopted to control this situation. Foaming agents do not need downhole modification, can be tested easily on existing wells and facilities, and are chemically compatible with corrosion inhibitors, so the same injection points and devices can be used.