This paper describes a rigless and cost-effective field implementation of conformance polymer sealant (CPS) and particulate-CPS (PCPS) systems used successfully in high-permeability and low-pressure reservoirs for zonal isolation intervention. The CPS system is an organically crosslinked polymer that is thermally activated to effectively seal the targeted interval. The PCPS system combines the CPS system with particulates that provide leakoff control to help ensure shallow matrix penetration of the sealant. The traditional method for zonal isolation consists of rig intervention for cement squeeze, which can be time-consuming and expensive. In high-permeability and low-pressure reservoirs, several unsuccessful attempts can extend the intervention by two or more weeks. CPS and PCPS systems provide a predictable and controllable right-angle set time that can help to ensure sealing on the first attempt. These systems do not develop compressive strength, simplifying the cleanup stage by quickly and easily jetting it out of the wellbore with coiled tubing (CT), as opposed to cement that must be drilled/milled out. This paper describes laboratory evaluations, treatment design methodologies, and two case histories from Kuwait, including one well that produced 1,600 BOPD after reperforations.
Traditional approaches to saturation evaluation in conventional oil and gas reservoirs rely on relationships between resistivity and water saturation. These relationships are challenging to apply in coals due to complexities in their pore systems and gas trapping mechanisms. Therefore, geophysical log-based methods are not commonly employed for saturation evaluation, and core canister desorption measurements are the standard approach for gas content evaluation. Desorption measurements present their own challenge due to the unknown and variable volume of gas lost during core recovery, so an in-situ measurement of gas content is desirable. Advanced magnetic resonance measurements provide a resistivity-independent saturation evaluation that have been employed in the oil and gas industry for the past approximately fifteen years. However, previous approaches to these types of measurements have focused on the evaluation of conventional reservoirs and hence free gas, oil, and water volumes, and have lacked sensitivity to quantify adsorbed gas, which has a unique magnetic resonance response. A novel magnetic resonance acquisition scheme has been developed that provides sensitivity to both adsorbed and free gas, as well as water, allowing for the complete evaluation of fluid content in coal seams. This measurement has been employed in evaluating coal gas content for coal seam gas evaluation and coal mining optimisation with encouraging results.
As data processing capabilities improve electronic device performance, it becomes necessary for Oil and Gas operators to understand how computing power can be harnessed at the extremities of their production network by deploying Edge Analytics solutions. This paper will discuss adapting the Industrial Internet of Things (IIoT) in the Upstream Automation domain, specifically in Artificial Lift assisted production, and will shed light on how Edge Analytics can be leveraged to deploy Machine Learning Models (MLMs) directly at the wellhead.
This case study highlights the field-trial of a pump-out stage tool, pump-out float collar, and the annular casing packer. These technologies were integral to drilling and completing wells in the Santos coal-seam gas (CSG) development of the Roma field in the Surat Basin of southeast Queensland.
Pump-out systems—which allow a primary cementing job to be performed above a slotted casing string using a pump-out stage tool, annular casing packer, and pump-out float equipment—eliminate the need for drill out operations. Once the casing is landed, a ball is deployed from surface to actuate the inflation of an annular casing packer below the stage tool and above the slotted casing. A second ball is deployed to shear and shift a sleeve to open the stage tool and begin the primary cement job. Once complete, a cementing wiper plug is released from surface and pumped behind the cement slurry to shift the stage tool into the closed position. The internal pump-out casing components are displaced to the bottom of the well and require no further intervention.
This case history includes results of the initial field-trial runs and technical details on well configurations, slotted liner placement across the coal-bed intervals, pressure charts, cement-job data, shear information on the ball seat, detail on the stage-tool operation, pumping out the float collar, and displacement of the internal equipment downhole. These jobs planned to eliminate the need to run a dedicated drillout trip during initial completion and also the need to change out the pipe rams in the blowout preventer (BOP).
Ultimately, the pump-out system provides a full-bore casing geometry with no internal restrictions and is expected to reduce completion costs by 15%.
Huang, Zhe (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Su, Yinao (CNPC Drilling Research Institute) | Li, Weichang (China University of Petroleum) | Jiang, Tianwen (China University of Petroleum)
Radial jet drilling (RJD) is an unconventional drilling technology to drill multiple radial laterals by using a high-pressure liquid jet. It is a cost-effective alternative to bypass damage zones near the wellbore, restimulate the production of old wells and develop the unconventional reservoirs. However, due to the structure of the deflector and the diameter of the radial laterals, traditional well-trajectory measuring tools cannot be applied in the RJD wells. It hinders the conduct of some significant operations. The unknown trajectory is a crucial limitation to further development and field application of the RJD technology.
In this paper, except an introduction of RJD technology, a measuring system and a mini-tool were proposed for the attitude measurement and motion state recognition. Based on the navigation theory, a reckoning method of the trajectory was established. After that, an experiment study was carried out to test the performance of the measuring tool and the reckoning method. As results of the experiments, the average errors of the measured lateral length, inclination and azimuth are 8.12%, 5.10% and 5.10% respectively.
Badran, Mohammed (Drilling Technology Team, Exploration and Petroleum Engineering - Advanced Research Center) | Gooneratne, Chinthaka (Drilling Technology Team, Exploration and Petroleum Engineering - Advanced Research Center) | Saqqa, AbdulKarim (Kasab International)
In this paper, we present an innovative Rotating Continuous Circulation Tool (RCCT) that allows both limited rotation of a drillstring assembly and uninterrupted circulation of drilling fluid during making up of, or breaking out, a drill pipe, to/from the drillstring assembly. Continuous/nearly continuous drilling has many advantages such as reducing the risk of stuck pipe and wellbore collapse as well as the efficient removal of cuttings resulting in improved borehole cleaning. The RCCT is a sub with a central bore and upper and lower ends that connect to the drillstring assembly. The upper and the lower part of the RCCT are able to rotate independently and in unison through a clutch/sleeve system. A central bore valve that is coupled to the upper part of the RCCT is able to selectively open and close the central bore. There is also a side entry port in the sidewall of the upper part that is controlled by the central bore valve to selectively allow drilling fluid to be injected into the central bore. A preliminary field trial to validate the RCCT was safely and successfully performed in a hydrocarbon well during a cement cleanout operation. The four RCCT subs were successfully tested for rotation with the rotary table and for drilling dynamics while cleaning out cement. Recommendations for improvements from this trial test are planned to be implemented in future field tests.
The measured PVT properties of gas condensate reservoir fluid samples collected while logging from wells drilled with Oil Based Mud (OBM) will often suffer due to contamination from the base oil. The objective of this work was to investigate the effects on reservoir fluid PVT properties of certain components dissolving preferentially into the gas stream and from the reservoir gas into the base oil.
Using a modified slim tube set-up, a reservoir gas was contaminated with base oil from an OBM. The two fluids interacted within a porous media under reservoir conditions by injecting the reservoir gas into the slim tube that had been pre-charged with base oil. After displacing all liquids, gas samples were collected again under reservoir conditions creating a batch of contaminated samples.
Using the results of compositional and PVT data obtained from contaminated samples at the back end of the slim tube and the original clean reservoir gas, a fully compositional numerical simulation model was created to simulate the experimental results.
During the experimental work, after extended flow of the reservoir gas through the modified slim tube we noticed that the reservoir gas was being produced leaner, indicating that the heavier components of the reservoir gas were staying on the porous media.
Using the compositional simulation model, we tested the sensitivities of conditions under which heavy end stripping of the gas condensate components may occur and how to obtain cleaner reservoir fluid samples faster from wireline formation testers in OBM drilled wells.
The modelling work indicates that when the reservoir gas and base oil are more miscible cleaner samples are obtained sooner.
Throughout this work we have been testing the idea that, if not completely miscible, the near wellbore region will retain an immobile phase of base oil and that this stationary fluid may hold back the heaviest components native to the reservoir gas. Furthermore, perhaps by altering the properties of the base oil, miscibility between the reservoir gas and base oil can be increased and improved samples obtained faster.
Gu, Yue (China University of Petroleum, Beijing) | Gao, Deli (China University of Petroleum, Beijing) | Yang, Jin (China University of Petroleum, Beijing) | Wang, Zhiyue (China University of Petroleum, Beijing) | Li, Xin (China University of Petroleum, Beijing) | Tan, Leichuan (China University of Petroleum, Beijing)
Shale gas in the mountain area is exploited in well factory mode. Learning effect due to well factory mode significantly affect the drilling cost, which has a powerful effect on platform location. The learning index, which is quantitative assessment of learning effect in the process of shale gas exploitment, is made by adjusted cosine similarity in this paper. The learning index, of which data comes from adjacent well, takes drilling cost, the well length and drilling time into account. The platform location optimization model, which considers learning effect, maximum number of wells one platform allowed and well trajectory, is established. The genetic algorithm is applied to solve the optimization model and the genetic operator is improved base on shale gas exploitation in mountain area. All the calculation procedure of genetic algorithm is performed in this work. The case study indicates that the optimization model can reduce the platform amount in a given area and increase the well amount one platform drills, namely, reduce the drilling cost by optimizing the platform location. The study demonstrates that the platform location optimization model established in this paper can both effectively quantify learning effect due to the well factory mode drilling in mountain area and decrease the drilling cost.
As gas fields mature and water production increases, understanding and managing the dynamic flow behaviour of the well and production system are critical for maintaining, and even optimising, production. This knowledge could be the difference between a successful and an unsuccessful attempt at re-starting a wet gas well after it is shut-in. When a well is in production, choking the well to optimise stable facilities operation and maintain water production within the water handling constraints of the facilities can be a fine line between achieving continuous stable production and the well ceasing production due to high liquid loading.
This paper describes the successful kick-off and unloading of two high-water producing gas wells within the operational constraints of the offshore facility. Transient multiphase flow models were developed for a platform well and a subsea well to simulate the wellbore flow dynamics during start-up. The models were tested over a range of values for parameters such as reservoir pressure, inflow performance and water gas ratio for different kick-off strategies but always honouring the facility's water surge management constraints.
The outcome of these simulations facilitated the development of tailored bean-up strategies for each high-water producing gas well, which provided a mechanism to engage with key stakeholders and demonstrate confidence in the execution of these strategies. Dedicated procedures were developed and subsequently executed successfully to re-start the two wells with the wells continuing to produce after kick-off and unloading, operating within the water surge management limits of the facility. Similar strategies are being developed for other high-water producing gas wells including those with material sand production.
This paper demonstrates strategic capability to realise additional value using dynamic modelling to kick-off mature high-water producing gas wells through proactive development of mitigation strategies which avoid production disruption.
Nagar, Ankesh (Cairn Oil and Gas, Vedanta Limited) | Dangwal, Gaurav (Cairn Oil and Gas, Vedanta Limited) | Pandey, Nimish (Cairn Oil and Gas, Vedanta Limited) | Jain, Akanksha (Cairn Oil and Gas, Vedanta Limited) | Parasher, Arunabh (Cairn Oil and Gas, Vedanta Limited) | Deshpande, Mayur (Halliburton) | Gupta, Vaibhav (Halliburton) | Pande, Karan (Halliburton)
Increasing water cut in oil-producing zones is a common issue faced by operators, particularly for mature fields. Currently, where most of the decisions are governed by economics, incurring additional expenses with activities such as handling produced water becomes extremely undesirable. Depending upon the nature of the zone, one effective solution to this issue is chemical isolation. This paper undertakes this issue, discussing a case study of a successful zonal isolation operation using an organically crosslinked polymer sealant in a fractured zone with a gravel pack and screen completion for a reservoir with a subhydrostatic nature.
This zone was an initial oil producer in FM-01 sand of the Mangala onshore oil field and had been stimulated in 2011 with a fracture-pack completion. The zone was completed with screens and a gravel pack with 16/30-mesh sand and 5.5-in. screens across the producing interval. During a period of time, the zone (FM-01) began to produce a significant amount of water, resulting in excessive water cut. To mitigate the issue, it was decided to completely isolate the zone using an organically crosslinked polymer system as a porosity fill sealant. When prepared in the appropriate concentration, subject to reservoir temperature, this low-viscosity formulation (40 to 80 cp) turns into a permanent rigid gel with time. The particular challenges of this operation were the presence of high permeability streaks because of stimulation by hydraulic fracturing, extra pore space because the perforated interval lay within the gravel-packed screens, and the subhydrostatic nature of the reservoir. Extensive laboratory testing was performed to optimize the formulation at the desired temperature, measuring the time necessary for the viscosity to begin increasing and the minimum total time necessary to form a rigid gel.
The case study discussed in this paper features the successful application of the treatment using the spot-and-squeeze method with coiled tubing (CT) for the isolation of the zone. After allowing the setting time, pressure tests were performed, indicating positive isolation of the zone. After the pressure test, a jet pump was installed, and a drawdown was created to flow the zone. It was observed that production post operation was almost 95% less than production before operation at the same pressure drawdown, indicating approximately 100% zone isolation.