Multilateral wells have been routinely drilled for several applications, with shale plays representing a natural progression for its use. Augmenting a multilateral well with selective fracturing of each leg is as straightforward as fracturing a single horizontal well. Multilateral wells with cemented junctions provide a good alternative to improve the economics for the development of oil and gas shale-reserve projects. This paper provides a description of the primary reasons for improving development project economics.
Multilateral solutions provide the means to work within a limited surface access area and generate a reduced footprint while draining a much larger volume of the reservoir from a single-surface location. This solution presents a significant advantage when drilling in sensitive or restricted locations, populated areas, and areas in which land issues restrict access to multiple drilling locations. In addition, the cost and effects of large drilling pads or multiple wellsites are avoided.
This paper describes the results obtained from the implementation and execution of projects in which cemented junctions were created for a new dual-lateral well and for an existing well in North America. It also provides the average cost savings obtained when this approach is compared to that of a single main wellbore and describes well performance with commingled production rates above typical single horizontal wells.
Based on past experience, the use of multilateral wells with cemented junctions (applied for new and/or existing wells) can make significant contributions toward helping oil and gas shale-reserve projects to be economically feasible, whereas the economics of single horizontal wells do not offer advantages for a large development plan for oil-and-gas-industry operators.
The present work focuses on application of boron-based nanomaterial enhanced additive (PQCB) in water based mud system. The additive is specially formulated to improve friction, torque and hydraulic drag in challenging subterranean formations with bottom-hole temperature reaching 200°C. Extreme pressure tests were conducted using the standard 10 lb/gal and 13.5 lb/gal water based muds. For 10 lb/gal mud system addition of 5% of this additive gives torque reduction of 80% while for 13.5 lb/gal mud the torque reduction was 52%. We noticed an increase in rheology of the mud with the addition of this additive showing higher PV, YP and gel strength as compared to the commercially available lubricant. Low RPM rheology for high mud weight formulation showed a two-fold increase. Higher low RPM rheology will improve the drilling-hole cleaning and weighting materials suspension capability. PQCB also shows a consistent HPHT fluid loss control performance in 10 lb/gal and 13.5 lb/gal muds. This is due to its ability to withstand the higher conditioning temperature and prevent early breakdown of the polymers in the mud system. During a field trial in Myanmar at one of the wells with known hard subterranean formation, PQCB demonstrated an excellent performance with torque reduction of 36.36% and return permeability of 41% while the commercial lubricant gives torque reduction of approximately 13.64% and return permeability of 49%. Unlike any other ester based additives, PQCB shows no hydrolysis problem on both the mud systems tested. This enables the elimination of silicone and alcohol based de-foamers in the mud formulation. The nanomaterial enhanced PQCB additive is also biodegradable and helps to prevent the wear and tear of drilling tools that ultimately will reduce the overall production cost.
The application of measurement-while-drilling (MWD) survey corrections is a critical step to ensure that the required service level is met and that definitive surveys are accurate, secure, and delivered in real time. Over the complex life of a directional survey, it is critical that these corrections are applied in the correct sequence and that the final survey is delivered to the directional driller within a time frame that avoids delays for critical decisions.
Past methods of supplying survey corrections to the wellsite vary greatly in terms of both methodology and speed. Techniques that are commonly deployed include file transfer, email, and online file sharing. Although there are benefits of using these methods, each falls short in one or more areas; these areas can include speed, security, or accuracy. Because of the need for one or more specialists to analyze the data, large amounts of data are often imported and exported. This process is not only laborious, but can also introduce opportunities for error.
To overcome these challenges associated with supplying the survey corrections to the wellsite, a new survey correction platform and associated workflows were developed. The new platform takes advantage of modern advances in software development and infrastructure along with the lessons learned from previous generations of software. The use of the new survey correction platform and application enables a database-to-database solution that streamlines multiple areas of survey handling. These areas include the application of in-field referencing (IFR1), interpolated in-field referencing (IFR2), multi-station analysis (MSA), and MWD survey quality control. The most significant improvement, however, is the removal of manual survey entry and extraction from the survey processing database and field MWD database.
This paper outlines advancements made at multiple steps in the lifespan of a directional survey to increase the speed, reliability, and accuracy associated with supplying survey corrections to the wellsite. It also describes the applications of this process in a real-time environment.
Introducing a new technology that reduces uncertainty and therefore risk of harmful, unplanned hydrocarbon release during drilling operations by providing additional secondary well control functionality in the event of rig evacuation. In most well control events, rig personnel have sufficient time to secure the well by following recognized well control operating procedures, utilizing long established well control technology. On occasion, shut-in does not occur before evacuation of the Blowout Preventer (BOP) control panel locations or, post-evacuation it is uncertain if shut-in procedures have been followed successfully. For example, if evacuation was sudden and the well remains in an unknown condition, potentially releasing hazardous hydrocarbons and associated gases to the environment. The author will discuss in detail the background and rationale to the new technology, including a review of well shut in potential versus time / incident severity and other human factors present at the moment of making the evacuation decision. The system design and intended operation will be explained including, specifically BOP function and monitoring when rig evacuation is occurring or has occurred. Several real-life scenarios will also be described for which the new technology could be operated. The system is designed to be deployed as an additional safety system, supplementing the rig's existing secondary well control technology or integrated with existing equipment to provide additional well control functionality. The novelty of the approach is that nothing is known to currently exist providing this functionality.
Stick-slip oscillation is a recognized and documented drilling dysfunction that reduces drilling performance and increase well costs. Stick-slip is a drilling phenomenon associated with the use of fixed cutter bits that use a shear cutting mode and exacerbated by non-optimal weight on bit (WOB) and rotations per minute (RPM) settings. The bit speed can vary drastically from fully stopped to twice the RPM setting (0-200%) during periods of stick-slip oscillation. This case study details the benefits of an automated stick-slip identification and mitigation system and service using surface measurements for an Operator drilling in a geographically diverse area. The stick-slip mitigation service was successfully used to increase ROP, reduce the drilling time, and improve bit performance.
Traditional methods of reducing stick-slip include varying the WOB and RPM set points by the driller, which requires the driller to identify the stick-slip occurrences and manually manipulate both settings. Inefficiencies are inherent to this process as the driller is unable to accurately quantify the magnitude of the stick-slip period and set the optimal drilling parameters. Additional inefficiencies are associated with this method relative to how quickly the driller reacts to the onset of stick-slip and the frequency these changes are made while drilling.
An automated system was added to identify and quantify the stick-slip severity and to manipulate the top drive RPM speed to mitigate the stick-slip in real time. A real-time service complimented the automated system through the delivery of specialized training, remote settings maintenance, performance monitoring, and streamlining knowledge transfer.
Al-Ajmi, Khaled (Kuwait Oil Company) | Al-Hamadi, Ebrahim (Kuwait Oil Company) | Baqer, Yousef (Kuwait Oil Company) | Al-Qnaai, Mohammad (National Oilwell Varco) | Fayed, Moustafa (National Oilwell Varco) | Khalil, Karim (National Oilwell Varco)
This paper will discuss the deployment of the concentric dual-diameter fixed-cutter bit technology, which was introduced in January 2015. The bit was deployed and tested twice in a vertical application in Burgan Field south of Kuwait and achieved the fastest penetration rate in the application.
The concentric dual-diameter bit is composed of a smaller pilot and a larger reamer section, where the reamer section dictates the final drill size. Conventional fixed-cutter bits take very little advantage of stress-relieving the rock, as it only affects the borehole wall. Concentric dual-diameter technology bits are able to initially drill with a leading smaller pilot section efficiently to relieve the stress of the rocks. Subsequently, the reamer section removes the stress-relieved rock with lower mechanical specific energy compared to regular fixed-cutter bits, giving it the advantage to generate higher penetration rates. Another advantage of the concentric dual-diameter technology bits is the stability of the bit, since two gauge sections are available to be in constant contact with the borehole while drilling.
The 12 ¼ in. concentric dual-diameter technology bit in conjunction with a packed rotary BHA was tested in a vertical application in the Burgan Field south of Kuwait. The bit was able to deliver improved performance, achieving the fastest penetration rate of 152.4 ft/hr. The section drilled was 762 ft in length and consisted of shale and sandstone.
The performance capability was confirmed when the same bit was reused again in a similar application subsequently and was able to deliver the same consistent record penetration rate of 152.5 ft/hr. The section length in this second run was 610 ft. and consisted of similar lithology of shale and sandstone.
The 12 ¼ in. concentric dual-diameter bit was able to surpass the average rate of penetration for the same application in the Burgan Field by 35%, saving the operator drilling time and making the concentric dual-diameter bit design the top performing drill bit in the field.
Addagalla, Ajay Kumar V. (Baker Hughes) | Kosandar, Balraj A. (Baker Hughes) | Lawal, Ishaq G. (Baker Hughes) | Jadhav, Prakash B. (Baker Hughes) | Imran, Aqeel (Baker Hughes) | El-Araby, Mohamed S (Baker Hughes) | Al Saqer, Qassem R (Baker Hughes) | Ansari, Adel (Saudi Aramco) | Pino, Rafael (Saudi Aramco) | Gad-Alla, Ahmed E (Saudi Aramco) | Olivaresantunez, Tulio (Saudi Aramco)
Formation damage is a by-product of drilling, completion and production process and is attributed to many factors. In open-hole (OH) and cased-hole (CH) wells, hydrocarbon flow may be impeded by various damaging mechanisms caused by drilling and completion fluids, in-situ emulsions, water block, organic deposition and oily debris left downhole.
Mesophase fluids have been successfully developed to effectively resolve the persistent problem of near-wellbore damage. The physical-chemical properties of the mesophase systems include high oil solubilization, high diffusion coefficients through porous media and the reduction of interfacial tension between organic and aqueous phases to near zero, making them excellent candidates for removing formation damage. The chemistry of mesophase fluids makes the systems excellent choices for superior synthetic or oil-based mud (S/OBM) displacements in casing and for OBM filter cake cleanup in open-hole completion applications.
Mesophase fluids are thermodynamically-stable, optically transparent solutions composed of two immiscible fluids. They differ from ordinary emulsions because they can be prepared with little or no mechanical energy input. They are typically composed of a non-polar or oil phase, an aqueous phase, surfactant(s) and an optional co-surfactant. Depending on how they are formulated, they can exist in a single-phase or in a three-phase system, in which the middle-phase microemulsion is in equilibrium with excess water and oil. The formulation characteristics, phase type, and ultimately, the cleaning efficiency of a microemulsion is dictated by the hydrophilic-lipophilic balance between the surfactant(s) and the physico-chemical environment. The microemulsions described in the study are single-phase where oil and water are co-solubilized by the surfactant(s) and co-surfactants. The water/oil interface has a zero or near-zero curvature, indicative of the bicontinuous phase geometry that produces very low interfacial tension and the rapid solubilization of oil upon contact.
The formation of a mesophase does not ensure the fluid will solubilize oil effectively to leave surfaces water-wet. The mesophase behavior and cleaning efficiency can be altered by salinity, surfactant, co-surfactant, oil type, temperature and particulates. No two wells are identical and the physical and chemical conditions can vary greatly depending on the application. As a consequence, robust, optimized formulations are necessary and validation testing is required to determine the efficacy of a mesophase for a specific application, i.e., OBM displacement/cleanup and removal of formation damage in open-hole and cased-hole wells.
This paper presents a technical overview of mesophase technology and field applications that demonstrate the efficiency of mesophase fluids for removing S/OBM debris and filter cakes, reducing near-wellbore damage and improving well productivity.
In the oil and gas drilling process, measurement-while-drilling (MWD) systems are usually used to provide real-time monitoring for the position and orientation of the bottom hole assembly (BHA). The current MWD systems can be categorized into magnetometer-based systems and gyroscope-based systems, which both compute the wellbore trajectory based on stationary surveys at the desired station using a mathematical model with certain assumptions. This current technology neglects the actual trajectory between surveying stations. This research proposed a system using low-cost strapdown inertial navigation system (SINS) to avoid the limits of traditional methods.
Demands have been rising for a continuous survey that captures the actual trajectory between the stationary surveying stations, especially in case of directional drilling process. Based on this technology, "dogleg" along the trajectory can be estimated more accurately. Therefore, a low-cost SINS consisting of three MEMS accelerometers and three MEMS gyroscopes is proposed to estimate the trajectory and satisfy the cost demand of commercial companies. This MWD surveying system could eliminate the size constraint of conventional inertial sensors and thus can be used in small well drilling. The core algorithms in the system are SINS mechanization and unscented Kalman filtering (UKF).
Due to the large noise in MEMS sensors especially under large shocks and high vibrations, this wellbore survey system will exhibit an unlimited growth of position, inclination, tool face angle and azimuth errors if there are no external observations to update the surveying system. The following external aiding information can be used as updates for the MEMS-based INS in the drilling procedure: the length and velocity information of the total pipelines, the zero velocity information during periodic stop intervals and azimuth information from the magnetometers. Performances the following different solutions: (1) MEMS sensors; (2) MEMS sensors + length/velocity update; (3) MEMS sensors + length/velocity update + ZUPT; and (4) MEMS sensors + length/velocity update + ZUPT + mag-based heading were analyzed. The proposed method was validated by 4 different simulation cases with respect to a typical wellbore trajectory: build, hold and drop wellbore profile. Situations of external aiding information being temporarily unavailable were considered in the simulation. The performance and feasibility of the presented continuous borehole surveying method had been demonstrated in this paper.
The proposed low cost SINS-based MWD method can eliminate the costly nonmagnetic drill collars for the magnetometers, overcome the size limitation of gyroscope-based MWD systems for small wells drilling, survey the borehole continuously without interrupting the drilling process, and improve the overall accuracy by utilizing UKF technique.
Drilling contractors used to move onshore drilling rigs between two well sites (from the old location to the new location) using standard desert moving system with hydraulic jacks for lifting, gooseneck and dollies/wheels the rig pulled by Kenworth and sometimes pushed by dozer D8 as shown in Onshore rigs used to move using Kenworth, dollies and tires Onshore rigs used to move using Kenworth, dollies and tires
Onshore rigs used to move using Kenworth, dollies and tires
Onshore rigs used to move using Kenworth, dollies and tires
Number of required Kenworth for pulling and/or Dozer to push is depending on the rig weight, the mast and substructure height and the type of the sand dunes on the desert. The rig center of gravity location and maximum allowable inclination angle during rig move is another constrain which used to be mentioned on the rig operation manual during the mast up rig move operation. Number of available Kenworth, especially when more than one rig is moving on the same time represents challenges to the rig move operation.
Moving of other rig components such as mud tanks, generator sets, and VFD, houses etc needs more cranes and more civil equipment.
Due to long distance between old and new locations rig move operation sometimes involved disassembling and reassembling the drilling rig at new location. This operation includes disconnect and reconnect electrical cables and piping. mast up rig move is preferable only in case of short distance rig move depending on the rig design, mast up rig move saving time as it avoids rig disassembly and reassembly however the constrains to conduct the mast up rig move is considerable (such as having power cables on the moving path), the rig crew has to lay down the drill pipes from setback in order to prepare the rig for mast up rig move, lay down the drill pipe is reducing the moving weight on moving dollies and increase the rig maximum allowable inclination angle during the rig move. Operation of lay down the drill pipe at old location and handle it again to rig floor in the new location, in addition to moving the drill pipes as a separate load to the new location represents revenue and time loss.
After arriving the new location, the rig crew has to position and adjust levels of the rig components to achieve the rig lay out as per rig layout drawings. Maneuvering of the huge loads on desert to achieve the accurate positioning is hard task and it depends on personal skills and experience. If any relative distance between the components is not matching the approved rig lay out drawings, the drilling crew will face challenge to disconnect then reposition then reconnect electrical cables and piping.
Hu, Chaoyang (Northeast Petroleum University) | Ai, Chi (Northeast Petroleum University) | Tao, Feiyu (Northeast Petroleum University) | Wang, Fengjiao (Northeast Petroleum University) | Yan, Maosen (Northeast Petroleum University)
There are often plenty of horizontal planes of weakness in reservoir formations, especially in shale formations, as reported for a number of oilfields. Once the weak-plane fails, the formation will become unstable, and can easily undertake slippage across a large area along its interface. The number of casing failure caused by slippage of weak-plane has been increasing significantly in recent years. Wells with casing failure are concentrated in an increasing number of areas. However, there has been lack of research efforts on how to optimize cementing and completing parameters in order to prevent casing failure induced by formation slippage. To address the problem, a more advantage completing type has been elected by qualitative analysis. The calculation model of critical slip displacement in un-cemented conditions was established. A finite model was used to test and verify the analysis and the model. The critical slip displacement of casing shear damage was also calculated. In this study, a new cementing practice was then proposed by optimizing casing parameters according to API standards, and a new research method was also put forward by proposing new casing materials to effectively mitigate casing failure caused by formation slippage for the future. Modeling results indicate casing failure induced by formation slip is different from conventional casing damage. The slip displacement needs to be used to measure casing impairment inside of maximum stress. Casing elongation is the key parameter for controlling casing shear failure. The type that keep the weak-plane un-cemented exhibits a larger critical slippage displacement .So the casing with lower grade and smaller thickness is recommended in weak-plane if the casing could meet all other down-hole requirements. The new concept is very different from the common belief that the good quality cement and higher grade and thicker casing are safer. If the elongation of casing can be improved by 60%, the critical casing failure slippage displacement can be increased by 21.40%. In this study, a new casing design and well completion method to prevent casing failure caused by formation slippage was proposed, and some guidance was provided for manufacturing casing with new material that can effectively mitigate or delay casing damage.