Over the last few years, extended-reach drilling (ERD) field development has significantly increased globally, and its benefits are well recognized. ERD techniques are increasingly used to intersect hydrocarbon targets that are difficult to access due to logistic issues. While these wells are challenging to drill, complete, and service, the benefits can be significant. These benefits drive the development of technology and techniques to continuously expand the ERD envelope and increase the complexity of profiles to reach more challenging targets. The directional drilling and evaluation service supplier plays an important role.
Each ERD well has a unique set of challenges. Common to all ERD projects is that many aspects of drilling engineering principles are not only pushed to the limit, but become highly interrelated and sensitive to smaller changes than conventional wells. For this reason, a team approach to planning and executing ERD activities should be considered critical. Each team member should bring to the project relevant experience, knowledge, a range of field-proven technology, and a solid global support structure.
Drilling successful ERD wells in challenging conditions depends on various factors, which include careful planning and use of the latest technology. Planning involves understanding the geological structure, not only within the reservoir section, but also in the overburden where typically most of the time efficiency gains can be achieved. The last step in planning is designing an efficient bottomhole assembly (BHA) based on previous experiences, lessons learned and inputs from various teams. Good planning is supported by use of new technologies, especially tools that give real-time information, enabling quick and informed decisions to ensure safe and efficient drilling in a challenging environment. This paper discusses the planning and decision-making process to drill ERD wells by using latest real-time technologies in drilling challenging wells. This paper describes the experiences and huge success of drilling the longest 8.5-in. hole section in an ERD well, drilled and cased smoothly through challenging formations.
As an alternative to conventional proppant pack placement, propped pillar-fracturing promises more effective and conductive fractures that enable hydrocarbons to flow through open channels. Recent experimental and numerical studies confirmed that viscous fingering phenomena can be used to develop a proppant pillar-fracture type placement: High-viscosity, proppant-laden fluid can be placed, and then a low-viscosity clean fluid is pumped to carve pathways through the proppant-laden fluid in a dynamic, continuous process. However, the created channel pattern was found to be significantly dependent on fracture geometry and treatment design parameters such as injection rate, fluid pulsing time, and fluid viscosity ratio.
The objective of this study is to extend the numerical investigation and normalize it to develop a treatment design methodology for constructing proppant pillars throughout the created fracture. A computational fluid dynamics (CFD) model was constructed using commercial CFD software, simulating the flow of fluids inside the fracture and the resulting proppant pillar generation. The study focused on the effects of surface injection rate (1 to 40 bpm/cluster), pulsing time (5 sec to 5 min), and viscosity ratio (from 2 to 20) between the two injected fluids to develop correlations between these parameters and the created fracture geometry.
Based on numerical results, the viscosity ratio chosen to achieve the proppant pillars allows the use of conventional crosslinked fluid without a hindered settling agent. In these designs the settling of proppant into pillars can be made to occur after the end of the stimulation treatment. Controlled settling of proppant from a crosslinked proppant-laden slurry allows channel formation and creates wider propped fracture-width pillars as compared to current industry pillar-fracturing treatment techniques. The optimum channel pattern has small channel sizes, remains open under closure stress, creates more channels throughout the entire fracture area and maintains good communication between unpropped areas. A new dimensionless term, Dimensionless Stage Volume (VSD), is presented to describe the channel pattern inside the fracture. Smaller VSD numbers resulted in smaller and more distributed channels. Therefore, it is highly recommended to select and design a proppant pillar-fracture treatment to achieve the lowest VSD possible and create the optimal channel pattern.
Mishra, V. K. (Schlumberger) | LeCompte, B. (Murphy Exploration and Production USA) | Gendur, J. (Schlumberger) | Chen, L. (Schlumberger) | Garcia, G. D. (Schlumberger) | Dumont, H. (Schlumberger) | Cantwell, W. (Schlumberger) | Agarwal, A. (Schlumberger)
In order to reduce reservoir uncertainties, downhole fluid analysis (DFA) and the acquisition of highest quality reservoir fluid samples are of utmost importance, especially in deepwater Gulf of Mexico fields. While focused sampling technique has achieved these objectives in the most efficient and cost-effective manner for a wide range of the reservoirs, there are certain conditions where focused probe or conventional probes don't perform the best. Some of these challenging reservoirs include low permeability or laminated reservoirs, highly unconsolidated formations and reservoirs with highly viscous oil. A newly designed 3D radial probe provides sampling and DFA solutions in such challenging reservoirs. Large inlet flow area of the 3D radial probe facilitates efficient pumping and sampling in low mobility or laminated reservoirs. Conventional probe faces challenge of loss seals in unconsolidated reservoir which is overcome by radial probe due to its large sealing surface area.
A case study from deepwater Gulf of Mexico is discussed in which complex reservoirs are tested for DFA and sampling using a 3D radial probe. Formation density, spectral gamma ray and neutron logs determine formation porosity and presence of shale. Triaxial resistivity identifies laminated zones and a laminated sand analysis is performed to add about 35% hydrocarbon pore thickness when compared to conventional, non-laminated analysis. This data was coupled with the latest generation microresistivity imager which allows accurate identification of geologic features, from very thinly-laminated bedding to faults and fractures.
Fluid sampling and downhole fluid analysis are performed with wireline formation tester tool configured with conventional probes as well as 3D radial probe. Several pumping stations are performed, and 3D Radial probe enables sampling in thin low mobility rocks providing low contamination samples confirmed with the laboratory analysis. Insitu fluid analysis data was used for sample optimization, detailed downhole fluid characterization and reservoir connectivity assessment. The 3D radial probe also allows high quality pressure transient data for better permeability estimation. In addition, a vertical interference test (VIT) is performed with sink and observation probe configurations for vertical permeability and connectivity assessment.
Additional inelastic and capture spectroscopy measurements were taken about two weeks after the well was cased, which validated critical petrophysical measurements. The spectral data was also used to further characterize the formation mineralogy.
Shirdel, Mahdy (Chevron Energy Technology Company) | Buell, R. S. (Chevron Energy Technology Company) | Wells, Mike (Chevron Energy Technology Company) | Muharam, Cece (Chevron Energy Technology Company) | Sims, Jackie (Chevron Energy Technology Company)
Steam conformance control in horizontal injectors is important for efficient reservoir heat management in heavy oil fields. Suboptimal conformance and non-uniform heating of the reservoir can substantially impact the economics of the field development, oil production response and result in non-uniform steam breakthrough. In order to achieve the required control, it is essential to have an appropriate well completion architecture and robust surveillance.
Five fiber optic systems, each utilizing a unique steam conformance control completion configuration, have been installed in two horizontal steam injectors to help mature steam injection flow profiling and conformance control solutions. These fiber optic systems have utilized custom designed fiber optic bundles of multimode and single mode fibers, for distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) respectively. Fiber optic systems were also installed in a steam injection test flow loop. All the optical fibers successfully acquired data in the wells and flow loop, measuring temperature and acoustic energy.
A portfolio of algorithms and signal processing techniques were developed to interpret the DTS and DAS data for quantitative steam injection flow profiling. The heavily instrumented flow loop environment was utilized to characterize DTS and DAS response in a design of experiment matrix to improve the flow profiling algorithms. These algorithms are based on independent physical principles derived from multiphase flow, thermal hydraulic models, acoustic effects, large data array processing, and combinations of the foregoing methods for both transient and steady state steam flow. A high-confidence flow profile is computed based upon convergence of the algorithms. The flow profiling algorithm results were further validated utilizing a dozen short-offset, injector observation wells in the reservoir that confirmed steam movement near the injectors.
As the drilling industry enters the era of big data, it has become necessary to find ways to organize and understand the vast amounts of real-time high frequency data recorded.
The industry currently focuses on the peak and average values of the accelerations recorded down hole, and there is no established method to examine the trend of these accelerations. The methodology proposed in this paper first focuses on obtaining the actual unmodulated acceleration values from the recorded downhole gauge data and then processes these values to understand the trend of acceleration as the drilling proceeds. This demodulation (or deconvolution) of the recorded data can reduce the likliehood of false predictions and, at the same time, increase the credibility of the mode of acceleration predicted (and hence more accurately predict failure), which currently relies only on the experience of the engineer. Thus, this technique can make real-time data monitoring more reliable and simple. Further, if combined with a gamma ray log to know the lithology of the formation being drilled, this data monitoring technique can reveal a significant amount of information.
In addition, this paper suggests calculating instantaneous jerk intensity and decomposing it to its monotonic intrinsic mode function. This reveals that these monotonic functions follow a certain trend, which might be useful in future endeavors to understand the underlying physics of drillstring failure.
Phase behavior of reservoir fluids in nano-pores of shale can be quite different from that in a bulk space. Its accurate description can lead to more accurate estimation of hydrocarbons in place in shale, as well as better understanding of the mechanisms governing hydrocarbon recovery from shale. This paper presents both experimental and modeling studies of the coupled effects of competitive adsorption, capillary pressure and pore size distribution on the phase behavior of fluid mixtures in partially confined spaces.
Experimentally, we measured the pressure/volume (PV) relationships along isothermal temperatures for fluid mixtures (N2/n-C4H10 and CH4/n-C4H10 binaries) that were contained in bulk spaces (PVT cell) and in partially confined spaces, respectively. To make the so-called partially confined space, the PVT cell was connected to a container holding a shale core sample. The partially confined space consists of the pore space in the shale core and the bulk space in the PVT cell. Theoretically, we developed a phase-behavior model for partially confined fluids by considering competitive adsorption, capillary pressure and pore size distribution of the shale core. In this model, the bulk PVT space is considered to be a capillary tube with an infinite diameter, while the shale sample is deemed to comprise of a series of capillary tubes with various diameters.
Test results show that, at the same temperature, the bubble point pressure of N2/n-C4H10 mixture in the partially confined space is higher than that in the bulk space, while the bubble point pressure of CH4/n-C4H10 mixture in the partially confined space is smaller than that in the bulk space. When a fluid mixture comes into contact with a shale sample, the individual components in the mixture may be preferentially adsorbed onto the shale sample, leading to the competitive adsorption phenomenon. The competitive adsorption of gas mixture onto shale can change the initial mixture composition, and thus affect the phase behavior of the mixture. The theoretical model can be properly tuned to yield bubble point pressures that are well matching the measured ones.
Wu, Keliu (University of Calgary) | Chen, Zhangxin (University of Calgary) | Xu, Jinze (University of Calgary) | Hu, Yuan (University of Calgary) | Li, Jing (China University of Petroleum) | Dong, Xiaohu (China University of Petroleum) | Liu, Yuxuan (Southwest Petroleum University) | Chen, Mingjun (Southwest Petroleum University)
Understanding and controlling flow of the water confined in nanopores has tremendous implications in theoretical studies and industrial applications. Here we propose a universal model for the confined water flow based on a conception of effective slip, which is linear sum of true slip, only depending on wettability, and apparent slip, caused by the spatial variation of the confined water viscosity as a function of wettability as well as nanopores dimension. Results by the model show that the flow capacity of the confined water is 10-1~107 times of those calculated by no slip Hagen-Poiseuille equation for nanopores with various wettability, in agreement with 47 different cases from the literature. This work may shed light on the controversy over the increase or decrease in flow capacity from the MD simulations and experiments, and guide to tailor the nanopores structure for modulating the confined water flow in many engineering fields, including nanomedicine, water purification, energy storage as well as the flowback of fracture fluid in petroleum industry.
Realtime operations generate huge amount of data that are stored as chunks in the WITSML data standard. Current WITSML model (version 1.4.1 or prior versions) does not provide enough flexibility to categorize channels. It is a challenging feat for users to dig through WITSML log object from a specific hole section or from a specific rig activity to zero in on any specific time frame in the aftermath of a NPT. This paper proposes the framework for a smart framework that organizes drilling data based on the rig activity within appropriate hole section without making any changes to the WITSML standard. This framework identifies rig activity, macro states and well events.
This framework proposes a logical hierarchical tree structure starts with parent node based on hole sections, WITSML objects are aligned with corresponding hole sections. Each hole section is further divided into child nodes based on rig activity. Realtime workflows are aligned to the corresponding rig activity e.g. ROP optimization, wellbore stability workflows are aligned to drilling activity parent node. Based on this parent child relationship user can retrieve any Hookload sequence for any tripping operation, for any hole section without any hassles. Any changes within the framework, updated by the user, for the current activity will be auto adjusted for subsequent activities within the tree structure. Identifying risks and events from the historical wells for future analysis is often viewed as a time consuming task; this solution aligns risks and events for each hole section under individual rig activity making it easier to retrieve it from historical wells during well planning. Along with logical organization of drilling data, this framework also offers an Operational Time Vs Depth plot that provides a Bird's Eye view of the entire well operations.
This solution can be used as a comprehensive logical structure for managing realtime and historical data from configuration to operational execution. Managing of historical and offset wells is simplified at the click of a button compared to the conventional method of data search.
The workflow provides the flexibility for minimizing user intervention by eliminating the need for repetitive configuration activities for each hole section within the wellbore. This workflow can be effectively used by a novice or an expert user.
This paper introduces new concepts for high-efficiency, high-output neutron generators for the well-logging industry, incorporating planar field ionization (FI) ion sources, which can provide for an order of magnitude higher neutron yield at a fraction of the power of conventional designs. Neutron generators for the well-logging industry primarily use electron-impact ion sources, which have low ionization efficiency and less than 10% monatomic ion production. A magnetic field or higher gas pressure is often required for improving ionization at the expense of lower reliability, average neutron yield, and large Tritium activity. The planar, FI ion source concept was investigated, and studies of a 100-µA ion-beam interaction with a thin Titanium target shows the target’s temperature at maximum operating conditions, never exceeding the Tritium desorption temperature. Particle-in-cell (PIC) simulation software was used for simulating the ion-beam transport from the planar, FI ion source, resulting in a mostly ideal beam transport covering the entire surface of the target, which reduces the target’s operating temperature and, thus, eliminates T desorption, allowing for approximately an order of magnitude higher neutron yield, higher logging speed, and a significant reduction in rig time, as well as substantial cost savings.
Li, Leiming (Aramco Services Company: Aramco Research Center-Houston) | Al-Muntasheri, Ghaithan A. (Aramco Services Company: Aramco Research Center-Houston) | Liang, Feng (Aramco Services Company: Aramco Research Center-Houston)
Demand for water used in hydraulic fracturing is increasing continuously due to the implementation of oilfield technologies such as horizontal wells and multistage hydraulic fracturing. The rising cost of fresh water has motivated services and production companies to try to prepare fracturing fluids with less ideal water sources such as produced water and seawater.
Technically it is not too difficult to make fracturing fluids for medium-to-low temperature applications using salt water like produced water or seawater. However at high temperatures of, for example, 300°F or more, it is much more challenging to formulate stable fluids directly with untreated salt water due to the damages related to the high levels of salinity and hardness in the water. With innovative approaches and careful selections of fluid additives in our tests, potential fluid issues caused by low water quality and harsh downhole temperatures were resolved or mitigated.
A novel high-temperature fracturing fluid system was invented recently that could be prepared with untreated seawater having a TDS of, for example, about 57,000 mg/L. The fluids comprised of metal-crosslinked polysaccharide polymers, and remained stable at high temperatures of 300°F or more. In a typical test, the fluid viscosity stayed above 500cP (at 40/s shear rate) for at least 60 minutes at 300°F. The fluid stability could be further enhanced with the addition of a number of selected nanomaterials. For instance, when one of the nanomaterials was added to the above fluids at a dose of 0.02% by weight or less, the lifetime of the fluid viscosity above 500cP was extended by at least 30%. Tests also showed that, with the addition of the nanomaterials, the viscosity lifetime could remain the same even when the polymer loading was reduced. The fracturing fluids also consistently showed over 90% regained permeability in both coreflow and proppant pack conductivity tests. Overall, the novel seawater-based fluid system shows excellent high-temperature stability, minimum formation and proppant pack damage, and intrinsically low scaling tendency.
The synergetic behaviors among the fluid additives and the nanomaterials in the high-temperature fracturing fluids prepared with the untreated seawater will be discussed, and the field-related laboratory test results will be presented in detail.