An operator experienced sub-optimal drilling performance in a multi-rig, multi-well drilling campaign in the Sultanate of Oman. This paper describes collaboration between the operator and a bit vendor to establish key operating parameters for efficient drilling based on fundamental drilling mechanics and laboratory testing. The concept was implemented and validated in that field's 12 ¼″ section.
The method makes minimum weight on bit (WOB) and torque recommendations based on the observation that a critical depth of cut (DOC) should be exceeded if a polycrystalline diamond compact (PDC) bit is to drill efficiently. Below this DOC the drilling efficiency, which is inversely related to the mechanical specific energy (MSE), can decrease significantly depending on the rock strength and the downhole environment. This behaviour has been associated with a transition between shearing and grinding as the predominant rock destruction mechanism. Critical DOCs and corresponding WOB and torque levels were determined from a wide range of laboratory drilling tests in carbonate rocks. Initially bit design details and anticipated formation properties were used before a bit run to develop minimum WOB recommendations and torque targets which were communicated to rig site personnel in a run-specific drilling roadmap. Rig crews were encouraged to maintain WOB above the minimum whenever possible while avoiding damaging stick/slip vibration and observing pre-agreed bit, bottom hole assembly (BHA) and rig imposed limits. Later the pre-drill recommendations were supplemented by computing the real time instantaneous DOC during drilling and comparing this with the critical value for efficient drilling to indicate whether the current WOB should be increased.
Sub-optimal performance in early wells was frequently associated with parameters insufficient to achieve the critical DOC and torque. Penetration rate performance showed a significant and consistent improvement after adoption of the roadmap. The section average penetration rates increased by 45% and routine shoe to shoe bit runs were achieved where previously an average of 2.6 bits per well were required for this hole section. We conclude that ensuring DOC and torque exceeded the thresholds for mechanically efficient drilling provided an engineering basis for selecting WOB and was a major factor in the observed drilling performance increase.
In the planning phase this approach generates an engineered parameter roadmap tailored to each specific application and bit design, and provides WOB and torque targets as input for BHA design. Many other drilling parameter optimisation schemes require significant intervals of steady drilling to calibrate underlying models. Rapid changes in formation properties over the calibration interval could make the parameter recommendations inappropriate for the rock actually drilled. In contrast the method described in this paper uses real time, instantaneous performance measurements to determine whether the parameters are delivering mechanically efficient drilling. Its recommendations are consequently more robust against fluctuations in formation drilling properties, at least for the predominantly carbonate formations so far evaluated.
During a gas influx scenario in drilling and well operations, early detection is important in order to prevent harmful consequences to rig, personnel and environment. However, the influx of natural gas may be masked if the gas loading capability of the drilling fluid is considerable. This work aims to provide a methodology for predicting the gas loading capability of oil-based drilling fluids, such that precautions for early gas influx detection can be made also for HPHT-drilling with oil-based drilling fluids.
In principle, the bubble-point curve; i.e. the transition from single liquid phase to two-phase, of the mixture of drilling fluid and natural gas determines the maximum loading capability of gas in the drilling fluid at the actual pressure and temperature. In overbalance situations the gas loading capability is decisive for the volumetric response and severity of gas influx. Thus, the gas loading capability needs to be accurately described for hydraulic models used for well control. This paper describes a methodology for gas loading capability prediction based on the bubble-point curve as determined from thermodynamical equations-of-state calculations. Different thermodynamical models have been evaluated and compared with experimental data for OBDF–methane systems. In particular, the features and requirements for the models are discussed.
Strategies for tuning the models to experimental results are necessary regardless of the choice of equations. Both models and experimental data on gas loading capability versus pressure follow the linear Henry's law in the subcritical region, and deviate severely from this as the pressure is increased towards the dense phase region of the drilling fluid – natural gas mixture. The determination of the dense phase region is of particular interest, as for this region there exists no limit in terms of gas loading in the drilling fluid. The proposed methodology forms the basis of a promising tool for gas loading capability calculations that, if utilized in drilling simulation software, may improve understanding and help detecting gas kicks early, thus lowering the associated risks, in particular for HPHT-drilling.
Gerogiorgis, Dimitrios I. (Institute for Materials & Processes, School of Engineering, University of Edinburgh) | Reilly, Simon (Institute for Materials & Processes, School of Engineering, University of Edinburgh) | Vryzas, Zisis (Texas A&M University at Qatar) | Kelessidis, Vassilios C. (Texas A&M University at Qatar)
The demand for more efficient and reliable oil and gas drilling fluid systems drives their development with unprecedented sophistication: the key challenge is to achieve predictable rheological properties, but also to enable their judicious customization, particularly for High Temperature High Pressure) (HTHP) applications and tough environments. This study presents the development and validation of a first-principles multivariate rheological model, allowing yield stress and viscosity prediction for new drilling fluids with iron oxide nanoparticles (NP).
Previous studies show that water-bentonite suspensions of variable Fe3O4 NP concentration exhibit non-Newtonian shear-thinning behavior, accurately captured via a tri-parametric nonisothermal Herschel-Bulkley (HB) rheological model form; nonlinear least squares regression yields reliable parameter sets. The resulting fluid shear stress and viscosity are expressed as explicit functions of independent variables (shear rate, temperature, NP concentration) and the correlations are validated against experimental data. A new parameter set must be computed by nonlinear regression for each combination of conditions, a necessity compromising the predictive potential of this data-driven rheological modeling approach.
To obtain truly predictive, first-principles rheological models, a systematic strategy is presented: shear stress and viscosity have now been expressed as physics-based (not data-driven) multivariate correlations of the aforementioned independent variables, using microscopic arguments for colloidal particle behavior, as confirmed by Transmission/Scanning Electron Microscopy (TEM/SEM) images. Shear stress is thus studied by distinguishing key additive contributions, on the basis of explicit bounds on colloidal inter-particle distances: our novel functional forms consistently capture the non-Newtonian fluid behavior, but require only one parameter set computation for the entire dataset.
In recent years different new services for formation sampling while drilling operations were introduced. The provided and implemented technology is primarily focused on the delivery of representative single-phase fluid samples. The formation sampling while drilling tools are equipped with various unique fluid identification sensors. These sensor modules deliver multiple physical properties and are commonly used for clean-up monitoring. Due to the extended downhole time during long drilling runs and the tough drilling condition ruggedized sensor elements have to be implemented. In addition, the same challenges regarding pressure, temperature and size as with wireline tools have to be considered.
The described logging-while-drilling (LWD) fluid analysis and sampling service is now extended by delivering optical absorbance spectroscopy and fluorescence measurements under in-situ conditions. This sensor system is added to the already existing sensor elements like pressure and temperature as well as measurement cells for density, viscosity, sound speed and optical refractive index. In addition, the lately introduced compressibility value derived from the electro-mechanical pump offers a bulk measurement, where localized sensors observe scattered data. As while drilling applications are often limited by the reduced bandwidth between the downhole tool and the surface acquisition system readings from the new optical sensor modules will be added to the fluid-typing algorithm, previously based on density, compressibility, refractive index and sound speed measurements, for improved predictions during sampling operations.
This technology should expand the application of fluid analysis in the downhole environment, gaining a deeper understanding of the reservoir fluid as well as improving the reservoir characterization and classification. With the new optical sensor system which provides distinct wavelength measurements in the visible, near infrared as well as ultraviolet range, a more detailed analytics of the formation fluid is possible. It will enhance the differentiation between water based mud, formation water and injection water as well as oil based mud and oil. It improves contamination monitoring and delivers a more detailed chemical composition while sampling. This new sensors will increase the success of fluid analysis only jobs.
Field examples will demonstrate the new sensor capabilities and will evaluate the data accuracy. The data interpretation allows for a broad comparison between different environments and the according sensor behavior. The review includes results from different reservoirs in various regions around the world.
Engelke, B. (Schlumberger) | de Miranda, C. R. (Petrobras) | Daou, F. (Schlumberger) | Petersen, D. (Schlumberger) | Aponte, S. A. (Schlumberger) | Oliveira, F. (Schlumberger) | Ocando, L. M. Sarcos (Schlumberger) | Conceição, A. C. F. (Petrobras) | Guillot, D. (Schlumberger)
In a joint effort, an oil and gas operator and a service company have undertaken research to help overcome well integrity and cementing fluids challenges in the presalt wells of Brazil where some fields present high levels of CO2 in reservoir fluids. Results are provided from the laboratory phase to cement placement evaluation.
The new approach is to provide a cementing system that is not only resistant to CO2 attack but also has a self-healing capability in the presence of fluids containing CO2. The validation of the CO2 selfhealing and resistant cement technology was initiated at laboratory level. Then, a yard test with real-time field parameters was performed, proving that the new slurry can be mixed and pumped using conventional cementing equipment. Finally, an onshore well in Brazil served as a test well for deploying and evaluating the new CO2 self-healing and resistant cement system in the field.
The technology consists of an engineered particle size distribution (EPSD) blend containing a reactive material that swells upon contact with CO2. This swelling allows the closure of microfissures and/or the reduction of the microannulus, which heals the cement sheath and reestablishes the integrity of the well. Then, a large-scale yard test was performed to evaluate real-time field parameters such as the fluidity and homogeneity of the dry blend and the mixability of the slurry using conventional cementing equipment. After the success of the yard test, the technology was deployed in Brazil. During the field test, 8 m3 [50 bbl] of 1,900 kg/m3 [15.8 lbm/gal] CO2 self-healing cement was pumped downhole and placed in the annular space between a 7-in. casing and a 8.5-in. open hole to promote casing support and zonal isolation in the production zone.
The CO2 self-healing and resistant cement overcomes the deficiencies of conventional Portland cement in carbon dioxide environments and presents an advantage over other available technologies designed to withstand CO2 attack by maintaining zonal isolation and long-term well integrity. Moreover, this technology can be applied in any field in the world where CO2 is regulated and/or entails risk for operators or the general public.
This paper describes a collaborative effort between an operator, a drilling contractor and a service company to introduce specific aspects of automated technology to a major drilling operation. The application of automated technologies to the process of well construction is emerging as a key lever to improve the overall efficiency of drilling performance. Though not yet mainstream, several recent applications have demonstrated that the technology maturity is no longer the limiting factor in accelerating the uptake and realizing the benefits that automation can bring to drilling.
A major challenge that has emerged in implementing drilling automation is the fragmented and often non-symbiotic business model that exists between key stakeholders. Additionally challenges exist around the lack of inter-operability between various parties' specific hardware and software. This issue extends to the multiple data streams involved, the data's robustness and how to integrate these adequately to drive automated processes. As with any technology introduction, new complications appear and this is no different for implementing automation technologies in drilling. Among the many new challenges are the increased cyber-security risks introduced by exposing the drilling control system to external networks, as well as the human factors challenges associated with changing well established workflows on the rig floor. The sum of these is to manifest itself in improved drilling performance without compromising on the safe operation of the rig. In this particular case, the discussion centers on the application of automation to drilling parameter control as it relates to improving the rate of penetration in hard rock drilling environments.
Successful implementation of automation technologies in drilling is a significantly complex endeavor, and the measures of success may not be immediately apparent. Instead, a vision that encapsulates a longer term, strategic view on the potential benefits that automation can bring to well construction is required, with shorter term tactical milestones being well defined, and a systematic plan engaged to achieve them. The paper explores how the above issues were managed over a testing and implementation period of approximately three years covering the transition from an advisory mode system to an automated one.
Automated process control applications on drilling rigs will continue to increase in both the number of deployments as well as the breadth of functions covered. The project described illustrates one approach that is unique to date in terms of the technology and the degree of collaboration employed by the stakeholders to successfully deliver the objectives. Early adoption initiatives as discussed here are essential for the technology to evolve. They provide the industry with a series of lessons that help to sustain and direct the future of drilling automation and its role in enhancing well construction capabilities.
Managed Pressure Drilling (MPD) enables safer operations and reduces non-productive time and thus provides the opportunity to reduce well costs. Many operators however, are not fully embracing the opportunity offered by the technology, due to strict regulatory requirements, and their perception that MPD is complicated and increases risk. A basis for this perception is that operator engineers in their designs, and contractor drilling crews in day-to-day operations, are insufficiently MPD experienced to fully and safely exploit the benefits of the technology.
Today, the advanced, and field proven, engineering (mathematical) models that are part and parcel of the software used in well design are also available in state of the art simulators. These engineering models and model based simulators are used by engineers during the design phase of MPD projects to replicate the conditions that will be encountered during actual well construction; picking optimal casing setting depths, using different equipment set-ups, selecting optimal drilling parameters and demonstrating the integrity of the design under a wide scenario of well conditions.
Once the well design is finalized, and before drilling operations commence, the same well design is programmed into a real-time drilling simulator. During subsequent simulator exercises,, rig personnel are exposed to the range of scenarios that can unfold during actual operations, taking into account uncertainties and unexpected events. Crews, at the hard end of operations, are able to hone their competence to deal with the unexpected in a team environment under the supervision and guidance of experienced coaches.
During actual MPD operations, the same advanced models can be used for automatic simulation and well monitoring purposes; they can also be integrated into the MPD control system to accurately maintain the required well pressures.
This paper describes the models used and both the classroom simulator-based engineering training and the real-time rig floor simulator training that will respectively provide operator engineers and contractor well site staff the in-depth understanding of MPD that will enable them to develop their respective skills to safely and cost effectively exploit the many benefits offered by MPD.
This paper covers the development, field testing and execution of a foamed spacer fluid on a conventional oil/gas block in India. It discusses the equipment and processes necessary to apply this technology of foamed spacer in production casing and the advantages of its application.
Sustained Casing Pressure (SCP) is one of the major challenges in many wells. This pressure resulting from poor zonal isolation by primary cement jobs represents a safety hazard, can influence production rates and in a worst case could compromise the structural integrity of the well. One cause of SCP in the wells was determined to be incomplete removal of drill cuttings and mud resulting in poor cement bonding. This results in micro-annulus/channeling within the annular cement sheath, thus allowing shallow formation gas to percolate to surface resulting in SCP.
The primary cement job for production casings is critical to the success of a well completion. In many instances, the use of conventional spacer technology has not managed to produce a good cement bond. This paper discusses how a foamed spacer system can be designed and used to increase mud removal and improve the quality of the cement job.
Foaming the spacer drastically increases its ability to effectively displace drilling mud and drill cuttings. This is achieved as a result of high annular velocity present even in large washed-out hole. The foamed spacer also typically has a higher yield point (YP) which helps in proper mud removal. In addition, foaming will increase the volume of the spacer, and extra volume allows longer contact time.
This paper highlights a case study for the application of foam spacer and documents the lessons learned. Job execution of foamed spacer is the basis for further improvement and implementation of foam technology for cement system as well. The paper also illustrates advanced laboratory tests done, such as effect of foam cement on skin damage, foam stability tests at downhole conditions, permeability tests, etc.
Lost circulation is a time consuming and expensive challenge, costing the oil and gas industry billions of dollars each year in materials and non-productive time. To mitigate lost circulation during cementing operations, a better understanding of how wellbore strengthening mechanisms apply to cement slurries is necessary. The ability to control cementing fluid properties to strengthen the wellbore and minimize losses during cementing operations is imperative for achieving adequate zonal isolation.
A comprehensive field analysis was performed to understand lost circulation initiation during different phases of drilling and primary cementing. Offshore wells from four different locations were studied: Gulf of Mexico, United Kingdom, Angola and Azerbaijan. In parallel, laboratory research was performed to understand the behavior of cement slurries in controlled lost circulation scenarios using a block tester. Measurement of formation breakdown pressure and formation propagation pressure were made with different cement slurry compositions and compared with pressures obtained with drilling muds.
In an analysis of 40 well sections that reported losses prior to, or during, primary cementing operations, the rate and severity of lost circulation varied for the wells studied, but it was concluded that losses were commonly induced while running casing or pre-cement job mud circulation, but rarely during cement placement.
The laboratory research confirmed the field observation: It would take much more pressure to open or re-open an existing fracture with cement slurry than with a synthetic oil-based mud.
This paper will present findings from the field analysis and laboratory research. It will also discuss strategies to prepare the wellbore for preventing losses before the cementing operation and to optimize cement formulations in case losses have been induced during drilling, casing running or pre-job mud circulation.
Han, Runqi (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | Pryor, Mitchell (The University of Texas at Austin) | Oort, Eric van (The University of Texas at Austin) | Scott, Paul (ConocoPhillips) | Reese, Isaac (ConocoPhillips) | Hampton, Kyle (ConocoPhillips)
Wellbore instability and stuck pipe incidents are large contributors to drilling-related non-productive time (NPT). Drilling cuttings/cavings monitoring is crucial for early detection and mitigation of such events. Currently, monitoring is done manually and lacks a streamlined approach. Automating this process would be very beneficial, and is possible due to recent advances in sensing technology. Real-time cuttings/cavings monitoring can be used to quantify cuttings volume, measure size distribution, and analyze shape. By correlating these measurements with ongoing drilling operations, the hole condition (in particular hole cleaning/cuttings transport efficiency, wellbore stability situation, etc.) can be automatically assessed in real-time. This makes pro-active prevention and mitigation of NPT related to hole cleaning and wellbore instability possible.
In this paper, we detail a system designed and prototyped to allow us to measure cuttings/cavings in real-time. A highly portable device employs a 2D high-resolution camera and a 3D laser sensor to determine the physical properties of cuttings. The 3D point cloud/depth data obtained by this device provides cuttings size distribution, volume and shape characteristics. Comparisons and discrepancies between expected and sensed quantities can then be used for alarming purposes and taking appropriate corrective action.
A prototype experimental setup was constructed to evaluate the ability to quantify relevant cuttings properties and profiles in the presence of drilling fluids. In a controlled environment, the cuttings slide down a shaker table's clearing chute while simulating various realistic external variable scenarios. The environmental impact on the accuracy, repeatability and robustness of the various sensors under investigation was determined to identify the sensors best suited for the task at hand. The optimum device configuration was then implemented and evaluated to verify that the system is viable for use in the field. The automated cuttings monitoring system can warn drillers to potential hazards associated with poor hole cleaning conditions, ongoing wellbore breakout, and the likelihood of stuck pipe events.