Radial jet drilling, RJD is an unconventional drilling technique that uses the jet energy of high velocity fluids to drill laterals with different geometries in both conventional and unconventional reservoirs. Many case studies are available worldwide have proven RJD as a viable alternative to traditional stimulation techniques, especially in marginal fields. RJD has a lot of application in the oil and gas industry. It is a cost effective completion technique to reach the untapped sweet spots, by-pass damaged zones near wellbore, re-complete old wells, etc.
The present paper outlines the basics of newly developed radial jet drilling technology. Advances in technologies, developments, forces imposed, jet fluid hydraulics, procedures, applications, and challenges of RJD are reviewed in this paper. Simulation studies and several worldwide case studies are discussed to evaluate the RJD technology.
For many years, Saudi Aramco and Schlumberger have collaborated to develop a downhole system to merge multilateral technology and intelligent completions to create the world's first "smart laterals." This was the vision of Saudi Aramco's push to drive ever higher recovery factors, an extreme reservoir contact (ERC) approach to reservoir management. These wells can contain upward of 20 km of reservoir contact and require appropriate compartmentalization to ensure uniform heel to toe production throughout the reservoir.
Proactive reservoir control is crucial for the efficient sweep of heterogeneous formations. This paper describes a full-scale multi-lateral, multi-compartment intelligent completion where many new technologies were integrated and demonstrated: Well construction and deployment practices to allow electrical umbilicals to be branched into laterals using inductive couplers. Deployment of revolutionary low power infinite position electrical flow control valves. Validation of a fully integrated production monitoring system providing direct downhole measurements of pressures, temperatures, flow rates, and water cut for each compartment. Integration of the surface acquisition and monitoring system with production SCADA to provide real-time downhole production information and health status.
Well construction and deployment practices to allow electrical umbilicals to be branched into laterals using inductive couplers.
Deployment of revolutionary low power infinite position electrical flow control valves.
Validation of a fully integrated production monitoring system providing direct downhole measurements of pressures, temperatures, flow rates, and water cut for each compartment.
Integration of the surface acquisition and monitoring system with production SCADA to provide real-time downhole production information and health status.
The ability to finely control downhole flow, measured directly at the reservoir face, has changed the way the industry will approach reservoir management. The sensing system has been validated with continuous compartment Productivity Index (PI), and multirate testing without shutting in the well. The SCADA integration allows a real-time management function where a compartment can be controlled to a target flow rate or draw down directly without resorting to traditional well system models to estimate choke orifice settings.
This paper highlights the development, installation, and validation of this new ERC well system and identifies some of the immediate production impacts emerging from this level of visibility and control at the formation face.
ERD wells are commonly associated with major challenges for installation of casing and liner strings. These wells typically present high torque and drag parameters that jeopardize getting strings to total depth.
In an attempt to optimize production, a major oil company in Angola decided to re-enter the study well in early 2016. A sidetrack was opened in the 9 5/8-in. casing, and drilling continued in the 8 ½-in. hole and penetrated the target zone in the highest location. Then a 7-in. production liner was run.
To reach the target zone, 5,583 ft of 8 ½-in. hole was drilled and deviations varied from 45° to 87°. This trajectory was a challenge for subsequent running of 7-in. liner. Torque and drag (T&D) models showed liner rotation at total depth (TD) was not possible, and a surge model indicated likelihood of mud losses while running the liner.
Liner hanger technologies became a very important phase of well construction, and service companies developed advanced liner hangers to overcome hostile well environments. In this case study, the short time available from the planning to execution phases and the current oil market conditions made it imperative that the right equipment, service, and technology were available in country. To achieve the ideal working parameters and get the liner to bottom, a thorough assessment needed to be performed to ensure risk mitigation.
This paper presents summarizes steps considered during planning for the 7-in. liner run including a detailed engineering analysis that enabled the operator to make the best decisions based on the available resources. The paper will also discuss lessons learned and best practices captured during the job that will be used for subsequent liners in similar wells.
The case study well was planned as a sidetrack from an existing well that had been shut in because of low performance. The main well had been drilled and completed as a single gravel pack in 2007. The objective of the sidetrack was to penetrate the reservoir organized complex in the structurally highest location to access reserves and optimize production. A constrained initial production was estimated at 6035 BFPD.
An operations overview of the complete intervention is as follows: Set a 8 ½-in. whipstock in existing 9 5/8-in. casing at 8,400 ft and mill the window. Drill an 8 ½-in. hole section to 13,923 ft MD / 6,657 ft TVD. Run and cement 7-in. liner. Displace the hole with completion fluid. Perform cement bond logs and hand the well over to completion.
Set a 8 ½-in. whipstock in existing 9 5/8-in. casing at 8,400 ft and mill the window.
Drill an 8 ½-in. hole section to 13,923 ft MD / 6,657 ft TVD.
Run and cement 7-in. liner.
Displace the hole with completion fluid.
Perform cement bond logs and hand the well over to completion.
The 8 ½-in. hole was drilled as shown in Well trajectory for case-study well Geometric features of case-study well
Measured depth at whipstock point 8,400 ft TVD at whipstock point 5,279 ft Deviation at whipstock point 78.25° Length of 8 ½-in. hole 5,583 ft Measured depth at TD of 8 ½-in. hole 13,983 ft TVD at 8 ½-in. hole TD 6,695 ft Maximum deviation in 8 ½-in. open hole 86.9° Maximum dogleg severity in 8 ½-in. open hole 5.21°/100 ft at 8,933 ft MD
Well trajectory for case-study well
Geometric features of case-study well
The operator and the liner hanger service company used proprietary simulation tools during the planning phase to predict possible issues for running the liner. The simulation considered main aspects, such as well trajectory and the influence of the whipstock installed in the 9 5/8-in. casing. All analyses were performed and maximum working parameters were defined and included in the well program. The operator also considered possible limitations that using standard equipment available in country might impose on well life. The final management decision was to proceed with the plan presented.
He, Youwei (China University of Petroleum, Beijing) | Cheng, Shiqing (China University of Petroleum, Beijing) | Qin, Jiazheng (China University of Petroleum, Beijing) | Wang, Yang (China University of Petroleum, Beijing) | Feng, Naichao (China University of Petroleum, Beijing) | Hu, Limin (China University of Petroleum, Beijing) | Huang, Yao (China University of Petroleum, Beijing) | Fang, Ran (China University of Petroleum, Beijing) | Yu, Haiyang (China University of Petroleum, Beijing)
Some wellbore segments have little or no contribution to total production rates because of reservoir heterogeneity, completion methods, and nonuniform formation damage along the horizontal wellbore. This work presents a semianalytical approach to determine the effective producing length (EPL) and production distribution of horizontal well, and further estimate the locations of malfunctioning horizontal wellbore and the segments of water or gas coning through the history matching of bottomhole-pressure (BHP) data.
In this approach, horizontal wellbore was divided into multiple producing segments and each producing segment (PS) can be considered as a cylindrical source. New pressure-transient solutions are further developed for a horizontal well with multiple segments of arbitrary length, production, skin factor, and spacing. This work obtaines the type curves and further investigates the effect of crucial parameters (e.g. EPL, spacing between PS, number, production and skin factor of each PS) on pressure-transient behaviors. Results show that there are distinct differences among type curves with different parameters above. A horizontal line with the value of 0.5/
The approach proposed in this work can be used to evaluate formation and well performance along horizontal wellbore so that engineers could make decisions on field strategies to improve well performance.
The global demand for energy is on the rise daily, this puts a heavy burden on Oil and Gas companies as the drilling and production challenges are increasing. Efficient and cost-effective solutions are always sought. Drilling multilateral horizontal wells is considered as one of the optimum solutions to maximize recovery with minimal cost in terms of wells drilled. The production from multilateral wells imposes it is own challenges, such as flow distribution and contribution from laterals. Installing smart completions in multilateral wells was a huge breakthrough and revolutionized the industry. The idea behind smart completions is to continuously monitor and control the production from each lateral individually. With the current configuration of downhole packers, the number of interval control valves (ICV) installed per well is four at most, which limits the number of effective laterals in a well. Considering the primary objective of minimizing drawdown and hence maximizing sweep efficiency from each well, it was studied and simulated that some reservoir compartments have an optimum number of five laterals, which makes it complicated to control and optimize the production.
This paper exhibits the deployment of the first "5-Zone Smart Completion" technology in a five lateral well, to control the flow contribution from each lateral. Each completion section installed is comprised of a gauge carrier, a hydraulic flow control valve, a packer with feed-through ports and a sub to accommodate and secure control line splices. The technology enabled the control of the flow rate from five different zones and the measurement of pressure and temperature from each compartment. The completion design included another two pressure and temperature sensors downstream of the flow, only a few hundred feet above the gauge of the upper zone, utilizing a single electric cable to power up and communicate with the surface panels. All hydraulic valves were successfully tested and fully cycled in place and the packers installed at the programmed depths upon installation. The technology enhancement that supported five zones completions ranges from material technology, which permitted enough metal to be removed from the packers, where seven, quarter-inch bores, have to be drilled for control lines to be run to accommodate electronics and telecommunications. This development enabled up to 16 sensors to be connected by one single electrical conduit. The paper presents the production string concept, the technology used to achieve seven bores in the packer, while maintaining the packer's integrity, the complete sequence of pre-job preparation, and the installation outcomes, with its impact on the downhole flow controls.
Telles, J. (Schlumberger) | Rojas, L. (Schlumberger) | Díaz, L. (Schlumberger) | Atencio, N. (Schlumberger) | Cortés, A. (Schlumberger) | Calderón, E. (Schlumberger) | Dorca, J. (Schlumberger) | Peñaranda, J. (Schlumberger) | Navarro, V. (Schlumberger) | Ydrogo, C. (PDVSA) | Mata, L. (PDVSA) | Correa, E. (PDVSA) | Páez, D. (PDVSA)
Accretion is a common phenomenon that affects drilling operations in the Orinoco Heavy Oil Belt. The main reservoir, where most horizontal sections are drilled, is the Oficina Formation. Accretion negatively impairs operational efficiency, thus generating stuck pipe incidents, problems while tripping due to high torque and drag values related to friction factors, and the unrecommended backreaming operations. In addition, accretion causes excessive fluid surface losses linked to plugged shakers screens.
This document shows the laboratory tests and successful field results obtained from the combination of specialized surfactant and lubricant agents working in synergy to reduce the accretion effect. The laboratory test demonstrated the synergy between the lubricant and surfactant in different tests, such as lubricity, accretion, and permeability damage testing. In the field, positive results were achieved in nine horizontal wells, thus increasing operative efficiency by reducing stuck pipe incidents, backreaming operations, and unplanned trips. This impact over flat times was also accompanied by a fluid waste reduction that improved the shakers’ screen usage and reduced the amount of oil coating the cuttings, which facilitated the treatment process and minimized environmental impact.
Zhang, Hao (Baker Hughes Incorporated) | Yuan, Peng (Baker Hughes Incorporated) | Wu, Jianghui (Baker Hughes Incorporated) | Mezzatesta, Alberto (Baker Hughes Incorporated) | Jin, Guodong (Baker Hughes Incorporated) | Satti, Rajani (Baker Hughes Incorporated) | Koliha, Nils (Exa Corporation) | Bautista, Juan (Exa Corporation) | Crouse, Bernd (Exa Corporation) | Freed, David (Exa Corporation)
Permeability is one of the most important characteristics of hydrocarbon-bearing formations. Many approaches exist for estimating permeability. Formation permeability is often measured in the laboratory from core samples or evaluated from well test data. However, core analysis and well test data are expensive and available only from a limited number of wells in a field. On the other hand, logging data are available from almost all wells. Therefore, accurate prediction of the formation permeability using logging data becomes very attractive.
This paper describes a unique integrated modeling approach to predict formation permeability. By combining digital rock physics (DRP) and downhole logging measurements, formation permeability and capillary pressure were predicted using computational analyses. In this approach, a representative geometrical rock model for the formation at each given depth of interest was numerically generated. These numerical rock models are constrained by the formation parameters derived from NMR and geochemical logging data, i.e., all input parameters for the geometrical rock model such as the rock density, porosity, grain-size distribution, and grain mineralogy, are directly or indirectly obtained from downhole logging measurements. Then, using the geometrical rock model as input, pore size information, capillary-pressure curve, and permeabilities were obtained by computational analyses, including fluid flow simulations based on the lattice-Boltzmann method (LBM).
To demonstrate the method's feasibility and applicability, the proposed modelling approach was used on two sets of field data from a North Sea well and an Austin testing well. Permeability and capillary pressure were experimentally determined from laboratory measurements on cores and compared to the simulation results. The predicted permeability values from the proposed DRP approach were in good agreement with measured values from cores. The drainage capillary-pressure curves derived from rock models also matched well with laboratory measurements on core samples. The promising results generated from this study demonstrate the feasibility of a digital core analysis method that integrates a geometrical rock model with downhole logging measurements to accurately and reliably predict formation petrophysical properties in a cost-effective and timely manner.
Syafii, Irfan (Saudi Aramco) | Mukhles, Amro E. (Saudi Aramco) | Driweesh, Saad M. (Saudi Aramco) | Shammari, Nayef S. (Saudi Aramco) | Bhattacharyya, Biswajit (Halliburton) | Solano, Jose (Halliburton) | Sethi, Neeraj (Halliburton)
Development of gas resources in the Middle East is taking an increasingly higher priority, driven by the growing demand for gas based power generation as well as the motivation for replacing oil as furnace fuel as is the case in several middle-eastern countries. Such fields are often characterized by corrosion formation fluids including CO2 and H2S, formation solids and other non-hydrocarbon components. These associated components have the capability to adversely affect on compatability with well completions, design of production facilities, maintenance costs, reservoir assets and product sales value among others. The failure to have such information could represent much more risk than taking the decision to perform downhole sampling and laboratory analysis.
Corrosion induced by the presence of sweet or sour gas combined with water production has led to major well integrity issues in some of these fields. Continuous monitoring and remedial programs have been implemented to issues either before or when they occur. Sacrificial tubing completions are deployed periodically inspected using corrosion monitoring tools and replaced based on established criteria. However, this process is associated with high monitoring, completion hardware, work-over and intervention costs.
Several corrosion studies in the past have been conducted to understand the properties of water and the effect on the precipitation and deposition of ferric salts in order to devise a predictive model for onset of corrosion which is related to tubular lifetime with a view of establishing a reliable corrosion preventive strategy which precludes expensive monitoring or remedial work-over operations.
In the past, produced water collected at surface was analyzed for chemical composition and PVT analysis but such results are inherently inaccurate due to the change in the chemical/composition and physical state of the water from downhole up to the surface. Hence there has been more focus on collecting "representative bottom-hole water samples". Memory based PVT samplers do offer this opportunity but suffer from the disadvantage of having to collect the samples "blind", quite often obtaining samples from the sump or coming back empty.
This paper presents a novel technique and engineering accomplishment which enhances the PVT and water sampling capabilities at in-situ conditions on gas producers in combination with full production logging stack deployed on electric line, offering real time control of the sampling operation. The volume captured is adequate for proper broad fluid analysis; lesser quantities generate uncertainties which ended incorporated into the results. Field case studies are presented based on the early stage successful deployment of this technology and its impact on facilitating the recovery of representative formation fluid samples.
Results of the fluid analysis have demonstrably improved the understanding of true water chemistry, which is a significant departure from earlier theories and contaminated measurements. Wells were sampled in order to carry out the risk assessment for corrosion and scaling tendency. The impact of the study on developing more effective well integrity and well intervention programs are also presented.to maintain the continuity of operations.
Horizontal and highly deviated well data that target pay intervals are generally clustered, both in a vertical sense, as they target specific stratigraphic levels, and spatially, as they target reservoir facies or fracture corridors. This means that the well data misrepresent the volume of interest, and the estimated facies and petrophysical property distributions are most likely biased. Nonetheless, to build reliable facies and petrophysical property models for petroleum exploration and production, geostatistical simulation methods require debiased input property distributions that are representative of the entire reservoir of interest. In this paper, we propose a new 3D kernel density based declustering algorithm to mitigate the inherent sampling bias in the input spatial distribution model and efficiently integrate horizontal and highly deviated well data as conditioning data in facies and petrophysical modeling workflows.
With growing regulatory requirements focusing on well safety and risk mitigating barriers, there is an increased requirement for surface-controlled subsurface safety valves (SCSSVs). Most SCSSV's provide well protection by means of a normally closed flapper-type closure mechanism that prohibits deployment of capillary or through-tubing based solutions which would not allow the flapper to fully close in the event of an ESD.
Operators desire cost effective rig-less deployment of capillary-based solution(s) to increase production and or reconnect a non-functional hydraulic control system. To date flow actuated subsurface controlled safety valves have provided a solution for loss of hydraulic control of a tubing-mounted SCSS; however, these valves are becoming less desired due to decreasing acceptance from regulatory agencies. Additionally, traditional post-completion chemical injection systems beyond a SCSSV have not been possible for continuous well-stimulant injection, nor has a solution for post-completion gage monitoring past a SCSSV been achieved.
This paper discusses technology enabling rig-less ability to reconnect a hydraulic system to a SCSSV or Safety Valve Landing Nipple by deploying a thru-tubing capillary based system inside the SCSSV / SVLN while maintaining functionality of the safety valve. In addition this solution can be utilized for continual injection of chemicals directly below the SCSSV and onwards to production zone depths. Further a downhole gage can be installed directly below the SCSSV and up to depths of 20,000 feet. Each of these functional characteristics can only be realized though the introduction of this novel capillary based solution, which maintains the "fail-safe" closure capability ensuring well control against a catastrophic event were to occurring at the surface or below.