This paper presents a case history of drilling automation system pilot deployment, inclusive of wired drill pipe on an Arctic drilling operation. This builds on the body of work that BP (the operator) previously presented in 2017 related to the deployment of an alternate drilling automation system. The focus will be on the challenges and lessons learned during this deployment over a series of development wells.
Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig's drilling control system. This platform hosts applications that interpret the activity on the rig and issue control setpoints to drive the operation of the rig's top drive, mud pumps, auto driller, drawworks, and slips. The second component introduced was a wired drill string, which provides access to high speed delivery of downhole data from a series of distributed downhole sensors, providing an opportunity to improve both automated control and real-time interpretation of downhole phenomena.
The project team identified several key performance indicators both at the project level and for each well. The project level key performance indicators (KPIs) were designed to give the operator an understanding of the reliability and robustness of the hardware and software components of the automation system. The KPIs for the well were designed to assess the impact of the technology on drilling efficiency through aspects of invisible lost time reduction (connection and survey times). The well level KPIs also fed into the project KPIs by capturing uptime, reliability, and repeatability of the hardware and software components of the system.
The paper describes several specific examples of where the benefits of the technology were realized as related to the KPIs above and describes some of the technical challenges encountered and fixes employed during the pilot campaign.
The paper also gives an insight into some of the non-technical challenges related to deployment of this system, around human behavioral characteristics. It discusses how focused collaboration and communication from all the stakeholders was managed and directed towards a successful deployment.
The work delivered on this project incorporates several technological innovations that were deployed for the first time on an active drilling operation. Delivery of these were important milestones for both the operator and the automation technology provider as part of their collaboration to increase the capability and reliability of these systems. The operator believes that this effort is key to allowing its drilling operations to realize longer term and sustainable benefits from automation.
Most carbonate reservoirs have fractures which have a detrimental effect on sweep efficiency during oil recovery. The objective of this research is to block the big fractures with polymeric particles and divert the injection fluid into the matrix for better sweep efficiency during CO2 floods. Polymeric particles have been developed that swell as salinity is increased. These particles are termed SISPP or salinity induced swelling polymeric particles. SISPPs swell more in higher concentration brine contrary to common polymeric particle gels (PPGs) which shrink. Water flood and miscible floods are conducted in fractured cores with SISPP placed in the fractures. The SISPP placement increases oil recovery in fractured cores during high salinity water floods and miscible/CO2 floods. Furthermore, a model for particle swelling, and the concomitant change in permeability, as a function of brine salinity was implemented in UTCHEM, and single phase and oil recovery corefloods were modeled. UTCHEM simulations showed good agreement with the experimental results.
Li, Maowen (CNOOC) | Lei, Guowen (Baker Hughes, a GE Company) | Zhang, Mingjie (CNOOC) | Coskun, Sefer B. (Baker Hughes, a GE Company) | Sy, Resksmey C. (Baker Hughes, a GE Company) | Hardikar, Nikhil P. (Baker Hughes, a GE Company)
The WEIZHOU-XYZ project is a newly developed offshore oilfield located in South China Sea. A quick and accurate productivity estimate would add valuable information to the decision-making on further field development, which is divided into three phases as per priority. A luxury dataset comprising seismic, drilling, well logs, well testing and production was acquired from most wells drilled in Phase-1. The objective of this paper is to establish a fast productivity forecasting method that can be used for the newly drilled wells of Phase-2 and Phase-3 after acquiring logging-while-drilling (LWD) data only.
The well-productivity forecasting model was based on uncertainty analyses using the Monte-Carlo method. Starting with equations of the production rate and the productivity index, each parameter of the equations has been investigated based on LWD data, and with a reference to the Phase-1 wells. Two key reservoir data used for the forecasting model are LWD formation testing (formation pressure while drilling - FPWD) and LWD nuclear magnetic resonance (NMR). These two dataset are the main information collected while drilling along with LWD resistivity and gamma ray in Phase 2. The FPWD data provides mobility, thus indicating the ability of fluid flow through the permeable reservoirs. The LWD NMR data provide continuous porosity measurement. Additionally, the T2 relaxation sensitives to both the pore size distribution and fluid properties providing estimation of formation permeability and fluid viscosity. Differing from the conventional way of a constant value input to the production rate equation, the proposed method sets all productivity related parameters (permeability, thickness, formation volume factor, viscosity, drainage radius etc.) under an uncertainty distribution range. The productivity prediction model is processed and evaluated using Monte-Carlo simulations. A scenario of 10,000 runs were conducted to account for the possible production distribution. As a result, an expected value of production rate or productivity index is used for the delivery of the possible forecasting outcome.
In this study, a successful application of this forecasting model has been proven by a good match with actual results from a well test. The observed difference is less than 5% between the real production rate and the expected value from the forecasting model.
This paper shows that formation testing while drilling and NMR while drilling together provide valuable inputs for productivity forecasting. The integrated method would be very helpful and meaningful for the production evaluation and decision-making for the Phase-2 and Phase-3 development wells, which will have limited data acquisition. A Monte-Carlo simulation workflow has been proposed for
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
Abbassi, Linda (OpenField Technology) | Tavernier, Emmanuel (OpenField Technology) | Donzier, Eric (OpenField Technology) | Gysen, Alain (ISP) | Gysen, Michel (ISP) | Chen, Chee Kong (Read Cased Hole) | Zeid, Ashraf (Eternal Energy) | Cedillo, Gerardo (BP)
Production logging in deviated wells has shown so far limited success in providing a reliable and cost-efficient method for production profiling. The reasons are numerous, but two factors are mainly responsible: conventional array production logging tools constitute very long toolstrings associated with expensive deployments, and data analysis is complex, requiring time-consuming analysis from cased-hole production logging experts. Overall, despite heavy investments made to perform downhole measurements, results are often disappointing and interpretation affected by a great deal of uncertainty.
A new instrumentation technology using microelectromechanical systems (MEMS) as well as new interpretation methods is offering new perspectives to this domain. In this paper, we describe a short and modular multiphase flow-sensor platform capable of achieving up to 10 times reduction in toolstring length compared to existing technology. Miniature pressure, temperature, optical, electrical, acoustic, microspinners, and ultrasonic Doppler sensors can be mounted independently from each other and easily interchanged to adapt the tool to address the well-specific challenges and meet the objectives of the surveillance program. By using both the sensor multiplicity made possible by hardware miniaturization, and diversity from multiple measurements, resolution and robustness is greatly improved. In addition, the use of digital power integrated into each individual sensor (smart sensor) provides calibrated data output, which highly facilitates the interpretation.
The new technology is an ultracompact array platform, with new sensors designs, whose superior measurements are enhanced by the new interpretation methods it enables.
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
Mohamed, I. M. (Advantek Waste Management Services) | Algarhy, A. (Advantek Waste Management Services) | Abou-Sayed, O. (Advantek Waste Management Services) | Abou-Sayed, A. S. (Advantek Waste Management Services) | Elkatatny, S. M (KFUPM)
ABSTRACT: Slurry waste management may involve injection of solid-laden fluids with concentration up to 25%. To accomplish this without plugging the near wellbore pore space, a fracture is created first using a pad of clean fluid. In some cases, where the formation has a high permeability-thickness product, kh, high injection flow rate is needed to open up the fracture with clean fluids. Most disposal wells do not have large enough pumps to provide the needed flow rates. A combination of a lack of geomechanical understanding combined with poor injection or facility design leads some operators to create high formation damage around their wellbores in slurry injection applications by injecting slurry at flow rates which are insufficient to open fractures. Moreover, the damage causes injection pressure to build up rapidly, facilitating the creation of short fractures which tend to cause near wellbore stresses to increase more rapidly for a given amount of solid deposition than is the case with longer fractures. This paper presents one case study which evaluates the injection well using operational data.
Slurry injection emerged in the late 1980’s and is one of the major environmental and economic methods of waste disposal management (Abou-Sayed et al., 1989; Moschovidis et al., 1998). In slurry injection, solids are slurrified with suitable carrying fluid (e.g. fresh water, produced water, or sea water) (Willson et al., 1998; Moschovidis et al 1999). The slurrified wastes are then injected into an underground permeable formation (Marinello et al., 2010). To provide the maximum possible storage space for the wastes, a porous formation that meets specific criteria is hydraulically fractured (Abou-Sayed and Guo, 2001). One of these criteria is a sufficient permeability to allow the liquids to leak off into the formation through the fracture faces (Van den Hoek, 2002).
During water injection, hydraulic fractures might intentionally or unintentionally be created (Morales, et al, 1986). During matrix injection of water, the permeability of the near wellbore region might decline (formation damage) by the accumulation of the suspended solids in the injected water to form internal and external filter cake (Bennion et al., 1996). The formation damage accumulation will cause the injection pressure to increase (Abou-Sayed et al., 2007). Once the pressure increases to a point that exceeds the formation fracture pressure, a hydraulic fracture will be unintentionally created (Elkatatny et al., 2017). The created hydraulic fracture will enhance the well injectivity and a sudden drop in the injection pressure will be observed (Abou-Sayed and Zaki, 2005). Unlike water injection operations, creating a hydraulic fracture is essential for a successful slurry injection project (Abou-Sayed et al., 2002; Majidaie and Shadizadeh, 2009).
ABSTRACT: This paper presents a numerical model for the simultaneous growth of multiple parallel hydraulic fractures with a constant height. The model uses an idealized formulation based on the Elliptic Displacement Discontinuity Method (EDDM). The EDDM assumes each fracture element to have displacement discontinuities of an elliptical shape and solves the one-dimensional elasticity problem. In addition to the EDDM, the model employs the multi-scale tip asymptotic solution that allows a coarser mesh near the fracture tip, compared to the Linear Elastic Fracture Mechanics solution. To show the capabilities of the developed model, the paper presents the comparison between the computed numerical solution and a reference solution. The latter is calculated using a fully 3D hydraulic fracturing simulator for multiple parallel hydraulic fractures. We investigate the effect of perforation friction and spacing on the results. The comparison shows that the EDDM model agrees with the reference solution when spacing between fractures is greater than the fracture height. However, a discrepancy appears in the zero perforation friction case once the fracture spacing becomes comparable or smaller than the fracture height.
Hydraulic fracturing is a method used to crack rock formations using high-pressure fluid. The technology is often applied in oil and gas well stimulation (Economides and Nolte, 2000), waste disposal (Abou-Sayed et al., 1989), rock mining (Jeffrey and Mills, 2000), and geothermal energy extraction (Brown, 2000). Typically, multiple fractures are simultaneously induced to reduce the operational costs. Therefore, the ability to simulate multiple interacting hydraulic fractures can improve the design of hydraulic fracture treatment. Hydraulic fracturing simulators often use various approximations that affect the accuracy and the computational time of the numerical procedures (Adachi et al., 2007, Olson, 2008, Kresse et al., 2013, McClure and Zoback, 2013, Wu et al., 2015, Peirce and Bunger, 2014, Peirce, 2015, Donlsov and Peirce, 2015a). Constant height hydraulic fractures, considered in this paper, resemble classical Perkins-Kern-Nordgren (PKN) fracture geometry (Perkins and Kern, 1961, Nordgren, 1972). The classical PKN model uses a local elasticity assumption and ignore. an essential part of constructing a simulator for multiple growing fractures - the interactions between the fracture elements. This issue is addressed by the enhanced PKN (EPKN) method for a single fracture (Dontsov and Peirce, 2016, Protasov and Donstov, 2017), in which the elastic interactions between cross-sectional elements are based on the elasticity equation for a planar fracture (Adachi and Peirce, 2008). The elliptic fracture opening profile from the classical PKN model is taken as an assumption for the EPKN method making it possible to reduce the planar elasticity equation to a one-dimensional relation. In addition, the EPKN method employs the multiscale tip asymptotic solution (Garagash et al., 2011, Dontsov and Peirce, 2015b) to make it possible to use a relatively coarse mesh near the fracture tip without losing accuracy, compared to the Linear Elastic Fracture Mechanics (LEFM). (As shown in (Dontsov and Peirce, 2016, Protasov and Donstov, 2017), the EPKN method possesses a high computational efficiency, compared to the fully planar simulators, while being able to accurately predict fracture size for a wide set of parameters.
Rock, Alexander (Clausthal University of Technology) | Hincapie, Rafael E. (Clausthal University of Technology) | Hoffmann, Eugen (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology)
This work provides an extensive review on Low Salinity Water Flooding (LSWF) recovery mechanisms, as well as an evaluation of its synergies with Polymer Flooding (PF). Thereby, a critical state-of-the-art evaluation on LSWF and PF mechanisms is combined with selective laboratory experiments, performed to illustrate the observations and findings. This evaluation can be used as a guidance to understand the expected behavior of both processes when applied in combination.
The work presented here comprises two main steps: 1) Comprehensive review of the mechanisms responsible of oil recovery in each process and 2) Predefined secondary and tertiary mode flooding experiments. First, oil recovery mechanisms associated to LSWF and PF have been analyzed in detail. Second, different field cases were compared in order to draw the main conclusions with regards to performance and recovery factors. This also helped to define the synergies of LSWF and PF in terms of technical and economic efficiency. Finally, secondary and tertiary mode experiments were performed to evaluate the feasibility of applying both processes.
Despite of the over 15 mechanisms reported in the literature for LSWF, six main mechanisms were identified that contributes to oil recovery. Mechanisms are described as: 1) Wettability alteration 2) Multi-ion exchange, 3) Fine migration, 4) Salting-in, 5) Double-Layer-Expansion and, 6) Other mechanisms, such as osmotic pressure and IFT reduction. Thereby, wettability alteration and fine migration have the highest significance. On the other hand, PF mechanisms were found to be: 1) Viscous fingering reduction, 2) Enhanced flow between layers, 3) Pull-out effects, 4) Shear thickening/elastic turbulence and, 5) Relative permeability reduction. LSWF field cases revealed incremental recoveries of up to 13% OOIP whereas synergies between LSWF and PF yielded to an additional recovery of 15% OOIP, underlining the potential of the combination of both EOR technologies. Selective LSWF-PF experiments performed in sandstones core-plugs in this work, allowed the verification of the additional recoveries reported in the literature. Tertiary flooding with solely LSWF, showed a lower recovery than tertiary LSWF-PF flooding. Moreover, this observation confirms the potentiality of polymer-combined LSWF in sandstones. Additionally, with the combined processes, a lower polymer concentration was required than applying a typically designed polymer flooding. This can be translated to an economic benefit for field applications.
Tertiary mode flooding experiments in sandstones and the analysis of field cases provided clear evidence of the advantages of LSWF-PF. This could yield that the processes -when applied in tandem- become a leading EOR strategy, ensuring the extension of the reservoir lifetime. Moreover, fellow researchers can benefit because the work provides a comprehensive review of Low Salinity Water Flooding and Polymer Flooding mechanisms. To the authors understanding, literature is currently lacking of such a review.
This paper considers the huge changes in the oil industry’s understanding of multiphase flow over more than 4 decades, and the application of that understanding into the engineering discipline of flow assurance that has developed in the same timeframe.
Initial test facilities were simple horizontal pipes carrying air and water at near atmospheric pressure and temperature. Then came larger, pressurised facilities using model hydrocarbon fluids. Now the oil industry has complex subsea production systems in deep water with reservoir fluids flowing over long distances and experiencing large changes in pressure and temperature. Fundamental understanding of the behaviour of the fluids and flow is key to the flow assurance discipline, and to the efficient design and operation of such production systems.
Techniques for visualising and modelling the flow, required to manage the various characteristics of the fluids and flow behaviour, are discussed. Significant challenges remain for flow assurance before it can predict all aspects of fluid and flow behaviour sufficiently accurately for risk management in all applications. Opportunities exist in oil and gas field development projects, and in subsequent operations, to instrument and monitor flow and fluid behaviour both for the benefit of the operation and for validation and improvement of models used in design.