This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage. This paper discusses the successful application of managed-pressure drilling (MPD) in the basin with reduction in risks and well costs. This paper discusses how managed-pressure-drilling (MPD) technology led to cost savings in two wells drilled in the Hai Thach gas field offshore southern Vietnam. This paper describes how a technique known as applied-surface-backpressure managed-pressure drilling (ASBP-MPD) can alleviate the limitations of conventional deepwater well control. The complete paper describes a recent directional coiled-tubing drilling (DCTD) job completed for an independent operator in the Appalachian Basin.
Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers. This paper presents a factory-model approach to improving CT drillout performance that has been used successfully for more than 3 years and has become standard practice. The oil industry is currently undergoing a technological transformation that will add value, improve processes, and reduce cost. Future drilling engineers will have knowledge of robotics, automation, and organizational efficiency, which is highly appealing for recruitment. This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage.
Repeatability of acquisition parameters for the base and monitor surveys is an important consideration for time-lapse studies of hydrocarbon reservoirs using controlled-source electromagnetics (CSEM). Variations in parameters such as source and receivers positions, conductivity and depth of seawater, etc lead to differences in the recorded EM fields that are often comparable to or exceed EM response due to production-induced changes in the reservoir resistivity. In that case, 4D CSEM is not feasible as long as 4D effects are analysed in the data domain. In the present study, we demonstrate the feasibility of 4D CSEM even for large differences in the acquisition parameters if the analysis is performed in the model domain. Using the “canonical” model considered by Orange et al. [Geophysics, 2009], we show that the repeatability requirements for water conductivity and receiver positions are relaxed approximately by an order of magnitude if the conventional sensitivity analysis is replaced by examination of inverted resistivity volumes.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 213A (Anaheim Convention Center)
Presentation Type: Oral
He, Jincong (Chevron Energy Technology Company) | Sarma, Pallav (Chevron Energy Technology Company) | Bhark, Eric (Chevron Energy Technology Company) | Tanaka, Shusei (Chevron Energy Technology Company) | Chen, Bailian (Chevron Energy Technology Company) | Wen, Xian-Huan (Chevron Energy Technology Company) | Kamath, Jairam (Chevron Energy Technology Company)
Data acquisition programs such as surveillance and pilots play an important role in minimizing subsurface risks and improving decision quality for reservoir management. In order for design optimization and investment justification of these programs, it is crucial to be able to quantify the expected uncertainty reduction and the value of information (VOI) attainable from a given design. This problem is challenging as the data from the acquisition program is uncertain at the time of the analysis. In this paper a method called ensemble variance analysis (EVA) is proposed. Based on a multi-Gaussian assumption between the observation data and the objective function, the EVA method quantifies the expected uncertainty reduction from covariance information that is estimated from an ensemble of simulations. The result of EVA can then be used with a decision tree to quantify the VOI of a given data acquisition program.
The proposed method has several novel features compared to existing methods. Firstly, the EVA method considers data-objective function relationship directly. Therefore it can handle nonlinear forward models and an arbitrary number of parameters. Secondly, for cases when the multi-Gaussian assumption between the data and objective function does not hold, the EVA method still provides a lower bound on expected uncertainty reduction, which can be useful in providing a conservative estimate of the surveillance/pilot performance. Finally, EVA also provides an estimate of the shift in the mean of the objective function distribution, which is crucial for VOI calculation. In this paper, the EVA workflow for expected uncertainty reduction quantification is described. The result from EVA is benchmarked with recently proposed rigorous sampling methods, and the capacity of the method for VOI quantification is demonstrated for a pilot analysis problem using a field-scale reservoir model.
Caliper logs provide valuable information on the shape and wear of casing and tubing strings at various times throughout their operational life. In turn, this information is used to determine the remaining design strength. To clearly distinguish deformation and wear from deviations caused by manufacturing tolerance, the caliper measurements can be compared with a baseline log run soon after a tubular string has been run, or with surface-inspection data. However, a baseline log may not always be available. This paper addresses these situations and provides an assessment of the useful information that one can obtain. A mathematical model, based on the properties of the discrete Fourier transform, is presented to determine the caliper offset center and underlying tubular ovality from six or more equi-angularspaced caliper readings. The series-expansion approximation enables these parameters to be determined as a best fit from raw, uncentered data to a numerical accuracy of approximately 0.01% in a single pass. This is consistent with the accuracy and resolution of the currently available calipers. Complete numerical results from test cases based on exact geometric shapes, such as an offset circle and centered ellipse, plus field examples, are also included along with implementation notes. The same calculations can also be used to determine the underlying elliptic shape and orientation of an openhole caliper. In the casing specification API 5CT (2011), internal dimensions are indirectly described in relation to the unloaded casing or tubing outer diameter and wall thickness at surface conditions. The manufacturing tolerances and resulting uncertainties may be significant compared with the wear, but in some cases one can obtain useful information with corrections for downhole tension, temperature, and pressure effects. Details of these corrections and a discussion of other sensitivities are also provided. Such algorithms are usually considered by the service provider to be proprietary, and little quantitative material has been published on them or their interpretation. Also, data are often presented to the customer in only center-corrected form, which greatly restricts future reprocessing. This emphasizes the importance of acquiring and retaining the raw data.
The operator of Well-A, a HPHT gas well in offshore Abu Dhabi faced a difficulty to drill ahead in a high-pressure fractured gas reservoir of “K” formation due to severe lost circulation followed by gas influx into the wellbore, namely loss/kick incident. The sudden and huge amount of mud losses at the bottom part of the reservoir led to gas flowing from the upper one observing a rapid pressure hump in the annulus between the wellbore and drill pipe. The operator then experienced complex well control situations including the burning of the entry gas to the atmosphere. The hole was finally plugged for the sidetracking due to a sticking occasion during the remedial action for the losses.
The integrated drilling team recognized a little or no success of drilling to the intended well total depth in case of continuously using conventional drilling methods, began to pursue alternatives and soon initiated Mud Cap Drilling, one of the MPD methods at the multiply fractured reservoir while drilling the 8-3/8” sidetracked hole. The application of the Mud Cap Drilling permitted efficient drilling resulting in 27 days’ time saving compared with the planned duration. Furthermore, it completely prevented the well from flowing and could make the un-drillable well drillable.
This successful drilling of the problematic gas reservoir using Mud Cap Drilling in the Well A has made a further encouragement of drilling HPHT gas exploration wells, which contain a lot of uncertainties in the formation pore pressure and fracture gradient profiles. The MPD as a flow control and pressure steering tool will prevent the forthcoming HPHT gas exploration wells from several drilling hazards resulting in NPT such as kick control, losses, wellbore instability, and differential sticking, slow ROP, etc. Moreover, it will allow minimizing the number of casing to be run and reducing formation damage to the gas reservoir.
This paper describes the positive impacts of the application using PMCD equipment, lessons learned from the implementation and areas for the further improvement of MPD application in future.
The HPHT well, Well A was drilled as an exploration and appraisal well between year 2012 and 2013 in the western region of offshore Abu Dhabi. Before drilling the Well A , approximately, 15+HPHT exploration wells had been drilled in offshore Abu Dhabi with the drilling target either at the base of “K” formation or in the “P” formation. “K” formation usually contains hydrocarbon gas and composes of limestone and dolomites with the development of natural fractures. The lithologies of the “P” formation are predominantly the shale, sand stones and silt stones.
The P-50 well duration of the “P” formation exploration well was estimated as 297 days referring to the drilling records of the past HPHT vertical exploration wells (Fig-1). The main problems experienced in the previous wells were, twist off /wash- out in the large hole size sections, mechanical sticking and drilling an abnormal formation pressure zone in the “G” formation in the 12-1/4” hole section, bit sticking and loss and kick controls in 8-1/2” hole section of the “K” formation and a slow ROP due to the hard sand stone presence and a high formation temperature more than 350 degree F in the 6” hole section of the “P” formation.
As long as underreamers have existed in the oil field, operators have wanted a clearer understanding of how these tools are operating in real time. A new integrated underreamer that provides real-time communication via the same mud pulse telemetry system as the familiar MWD/LWD/RSS (Measurement While Drilling/Logging While Drilling/ Rotary Steerable System) tools and allows the placement of the underreamer closer to the bit (to aid vibration management and minimize rat hole length), has been used. This advanced underreamer system reveals the current condition of the tool and the position of the blades (implied hole caliper) to the operator, additionally, it uses internal hydraulic oil pumped-pressure activation (and deactivation) of the blades. This integrated underreamer was used to simultaneously drill and underream an 8½-in. x 9?-in. pilot hole section interval and then side-track to drill an 8½-in. x 9?-in. mainbore lateral section to the top reservoir horizon.
A case study in the UK North Sea Harding field is included as part of this paper describing the critical challenges of simultaneously drilling and underreaming a development well, including the equivalent circulating density (ECD) management within narrow pressure margins. Underreaming an 8½-in. x 9?-in. wellbore all the way to TD was viewed as the most acceptable method to manage ECD and be able to get the production liner to bottom. Other ECD control methods used on this well, and detailed in this paper, include a combination of adjustments of rate of penetration (ROP) and rotations per minute (RPM), drilling fluid rheology management and pumping of sweeps at different stages of drilling to aid hole cleaning. The PDC (polycrystalline diamond compact) bit design was matched to that of the reamer with a proprietary technology to optimize the drilling assembly and minimize stick-slip or coupled lateral vibrations.
The reaming system was used to drill and underream 6,645 ft. in two runs totalling 288 hours on-bottom drilling, with minimal vibrations. The well was drilled with an inclined trajectory of up to 90° with as much as 5°/100 ft. dog leg severity. The reamer appeared to provide an in-gauge borehole allowing for successful running, rotation and cementing of approximately 4,300 ft. of 7-5/8” liner without any issues, demonstrating superior borehole quality.
This paper outlines the problems anticipated in this challenging well, the thinking behind the unusual reamer selection, the method for proper synchronization with the pilot bit, and the keys to overall success.
History and Background
Boreholes have been under-reamed for decades. Originally less reliable mechanical-arm devices were run after a borehole was drilled to a pilot size. The historical development of this technology, as well as significant improvements is described by Thomson, et al, 2008 in the following paragraphs.
This paper introduces a novel approach to the optimal design of the synthetic aperture method for marine controlled source electromagnetic (MCSEM) surveys. We demonstrate that the sensitivity of the MCSEM survey to a specific geological target could be enhanced by selecting the appropriate amplitude and phase coefficients of the corresponding synthetic aperture. We have developed a general optimization technique to find the optimal parameters of the synthetic aperture method. This approach makes it possible to increase the corresponding ratio between total and background fields within the area of an expected reservoir anomaly and in this way improve the resolution of the EM data with respect to potential subsurface targets. We also demonstrate that this optimal synthetic aperture method can be used for a removal of the distorting airwave effect from the MCSEM data collected in shallow water.