The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
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.
Yang, Zhaopeng (PetroChina Research Institute of Petroleum Exploration&Development) | Li, Xingmin (PetroChina Research Institute of Petroleum Exploration&Development) | Chen, Heping (PetroChina Research Institute of Petroleum Exploration&Development) | Ramachandran, Hariharan (The University of Texas at Austin, Hildebrand Department of Petroleum and Geosystems Engineering) | Shen, Yang (PetroChina Research Institute of Petroleum Exploration&Development) | Yang, Heng (China National Oil and Gas Exploration and Development Corporation) | Shen, Zhijun (China National Oil and Gas Exploration and Development Corporation) | Nong, Gong (China National Oil and Gas Exploration and Development Corporation)
The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area has been put into production about 10 years, existing problems of productivity declining and produced gas-oil ratio rising. Therefore, the development optimization for the early producing area should be conducted in order to obtain the more profitable oil recovery. A typical foamy oil reservoir simulation model using 5 components was created to understand the remaining oil distribution features. Based on above understandings, technical strategies were proposed for infilling well deployment in the early producing area. Results show that the gravity drainage and gravity differentiation of oil and gas during the cold production of foamy extra-heavy oil from horizontal wells by foam flooding are the main mechanisms for formation of remaining oil. And the influence factors of remaining oil distribution include horizontal well spacing, reservoir thickness, reservoir heterogeneity, interlayer distribution and reservoir rhythm. Thus tor foamy extra-heavy oil CHOP process, the enriched remaining oil area is the place between two adjacent horizontal wells with well spacing of 600m. Therefore, well infilling is an effective measure improving oil recovery factor of cold production, and the well infilling should be implemented as soon as possible to obtain better performance of cold production.
To validate the completion model, a computer simulation was performed in four scenarios to predict mechanical failure limits. Consequently, a completion design model was obtained using vacuum-insolated tubing (VIT) that enables a minimum of 75% of steam quality given an inlet steam quality of 80%. In addition, a seal bore is used at 50° to 60° of inclination, which enables the upper completion disconnection/connection through the seal stinger at that depth, without losing production capabilities for changes in the depth of top of connection of tie-back. This paper describes the type of completion development and challenges encountered during the design. The advantages and benefits of collecting the correct information in the process of thermal recovery in the joint venture are also discussed.
The investigation resulted in a completion model of thermal wells that will enable the monitoring of the conditions of the injection, tubing, casing, and injection effectiveness in the system in which the cyclic process is applied and adjusted to wells in the Orinoco Belt. A conclusion of this investigation is that, during the injection, the movement of production string and the monitoring component must be independent to avoid the transference of stress resulting from thermal expansion. Polished bore receptacles and seal assemblies should be used in the replacement of expansion joints; this will enable the upper completion to be used for recovery and changed for the injection system.
Although completion models have been developed in which the steam path can be monitored, they have not been developed previously for use in long horizontal section wells, as was performed in this case. The problem of thermal expansion of the tubing during steam injection is expected to be resolved with the implementation of the design based on this study. Feed-through packers have already been developed especially for this process, although with a mixed record of successful and unsuccessful deployments. The monitoring system must be mechanically independent of the injection system, such that movements associated with expansion and contraction do not have a significant effect.
Fu, Jin (CNPC Engineering Technology R&D Company Ltd.) | Wang, Xi (CNPC Engineering Technology R&D Company Ltd.) | Zhang, Shunyuan (CNPC Engineering Technology R&D Company Ltd.) | Chen, Chen (CNPC Engineering Technology R&D Company Ltd.)
Located in south of Eastern Venezuela Basin, Orinoco Oilfield is an onshore heavy oil field in South America. The heavy oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. According to the reserve report released by PDVSA by the end of 2016, JUNIN Block that is situated in east of Orinoco Oilfield has an OOIP of 178*108bbl.
Data of drilled wells and distances between offset horizontal intervals in Orinoco were both studied to improve ultimate production rates. 3-dimension borehole trajectories were designed and the most effective anti-collision measures were taken.
After optimziation 8-12 horizontal wells are distributed on one pad. As the horizontal interval extends, the stable production time is prolonged and the accumulative production per well improves. However, the recovery rate stops increasing when the horizontal interval is over 1600m in JUNIN Block. Economically a large space between offset horizontal intervals results in fewer wells and lower costs, but a smaller space contributes to a higher production efficiency per well. If the space exceeds 600m, the accumulative production rate increases much more slightly. A three-dimension well trajectory consists of a vertical interval, an angle building interval, an angle holding interval, an angle building & direction changing interval, a direction turning interval as well as an absolute horizontal interval.
Since Petrobras developed the first ever offshore deep reservoir (Lula) by scale in 2006, Brazil has been conducting a progressive campaign targeting hydrocarbons buried under deep water, which contributes to discovery of Lula, Carioca, Jupiter, Buzios, Libra and other giant presalt reservoirs in Santos Basin after Campos Basin, where there are 9 oil fields ranking among the top 20 offshore oil fields in terms of OOIP. By June 2017 over 160×104bbl oil and gas were produced per day in deep water of Santos Basin, taking up 57.1% of the total yield of Campos and Satos.
Creep deformation of ultra-thick salt beds, severe loss of limestones, poor drillability of formations and insufficiency of deep water drilling equipment all make drilling and completion challenges more complicated. Mud systems and casing programs are optimized to conquer creep of salt and formation of hydrates due to low downhole temperature. Turbines + impregnated bits are deployed to improve drilling efficiency of siliceous carbonates (Lagoa Feia A Group). Precise control of ECD and efficient LCMs solved engineering challenges caused by narrow density windows (Lagoa Feia B Group and Lagoa Feia C Group).
This paper submits the monitoring methodology applied to horizontal wells associated to the First polymerized water injection pilot project, developed in Zuata Principal Field from Hugo Chavez Orinoco Oil Belt (Venezuela). Zuata Principal is a mature field, formed by unconsolidated sands of deltaic and fluvial sedimentary environments, saturated with extra heavy crude of API gravity between 8.5 to 9.5, and viscosities between 2000 to 5000 cp at reservoir conditions. The basic units of production construction (Clusters) are mostly made of horizontal wells perforated in a radial pattern, which operate under the artificial lifting method of progressive cavity pump (PCP). The pilot project was developed in a deltaic environment. As a part of the surveillance plan of the project, it was established one methodology for the control of the producer wells, using the following sources of information: - Measurements of pressure and temperature at bottom hole (real time), using multiple pressure and temperature sensors placed in the horizontal section and temperature distributed sensors, meaning fiberoptic sensors.
This paper presents a practical method for benchmarking heavy oil fields as a tool for identification of opportunities for total cost and production optimization. The method combines actual data from typical heavy oil fields to define reservoir, well and surface complexity indices, for categorizing a subject field and a total cost breakdown model to map potential risks that could cause total cost to increase, potential project/ process delay and poor production performance. The benchmarking process consists of four steps: 1) classification of a subject field using Front End Loading (FEL) and complexity indices that account for: a) reservoir structural, stratigraphic, rock, fluid, energy, static and dynamic complexity, b) well complexity and c) surface processes complexity; 2) selection of analog fields within the range of indices; 3) use of causal maps to identify causes of uncertainty and risks that impact capital expenditures (CAPEX), operational expenditures (OPEX), production losses and cycle time; and 4) a total cost stochastic model is used to generate graphs providing the position of the subject field vs. analogs. A total undiscounted cost breakdown structure provided information on the most critical cost drivers, where significant impact corresponded to OPEX. Causal maps described typical total cost drivers for surface and subsurface.
Summary A workflow to generate seismic well ties in PS converted wave seismic sections using sonic logs was created by estimating Vp/Vs relationships and the time difference between the arrival time of the P-P and the PS waves to several key events. The results were PS converted wave synthetic seismograms tied to well-defined seismic reflectors at different depths. These positive results made possible the creation of a step by step workflow to tie wells to converted wave seismic and generate synthetic seismograms. Introduction The seismic method of reflection P-P wave has been the most important exploration method in the oil and gas industry. Nevertheless, this method does not clarify all the uncertainties that can be encountered during subsurface exploration and development.
Schedule Session Details Expand All Collapse All Filter By Date All Dates Sunday, December 09 Monday, December 10 Tuesday, December 11 Wednesday, December 12 Filter By Session Type All Sessions General Activities Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Energy4Me Training Course/Seminar Sunday, December 09 07:00 - 15:00 Field Trip: An Integrated Approach to Geologic Outcrops for Boosting Reservoir Understanding Jal Az Zor Escarpment, North of Kuwait City Ticketed Event Field Trip Jal Az Zor Integrated Field Course An Integrated Approach to Geologic Outcrops for boosting Reservoir Understanding When: 9 December 2018 Where: Jal Az Zor Escarpment, north of Kuwait City Organizers: KOC, with KOC and Shell SMEs The field trip will provide an integrated approach to geologic outcrops, using Jal Az Zor examples, that will trigger reflections in the participants about the implications of heterogeneities, scale, and 3D distribution of rock properties to models, studies, activities, and insights pertinent to reservoir analysis. The field course is specifically designed to relate the geology to a variety of subsurface disciplines involved in heavy oil development. Topics addressed will include baffles, reservoir modelling, steam conformance, cap rock integrity, well spacing, integration of well, reservoir, and facilities management (WRFM), and observation wells placement. The ultimate goals are to gain an appreciation for the value that the understanding of vital elements of rock description and sedimentology have for reservoir studies, and for the enhancement of production strategies. Group discussion will be encouraged to share knowledge and trigger new perspectives.