Devon Energy and its debt gets smaller, as Canadian Natural Resources adds to its huge, long-term bet on Canadian heavy and ultra-heavy crude. The recent production freefall could accelerate even further as US sanctions-related deadlines pass, the US Energy Information Administration said. The authors of this paper propose a novel work flow for the problem of building intelligent data analytics in heavy-oil fields. This paper presents the data collected by an ultrasound downhole scanner, demonstrating a novel method for diagnosing multilateral wells. Against the background of a low-oil-price environment, a redevelopment project was launched to give a second life to a shallow, depleted, mature offshore Congo oil field with viscous oil (22 °API) in a cost‑effective manner.
This paper will describe a methodology which has been developed as an alternative to four-dimensional (4D) Seismic. The main objective is to track heat conformance over time in the thermally developed "A" Field, Sultanate of Oman. The method has several significant advantages over 4D Seismic, including: Negligible cost and manpower requirements; Provision of close to real-time information and no processing time requirements; No Health, Safety or Environmental exposure, or disruption to ongoing operations.
Negligible cost and manpower requirements;
Provision of close to real-time information and no processing time requirements;
No Health, Safety or Environmental exposure, or disruption to ongoing operations.
The paper will also demonstrate the power of integrating wide-ranging data sources for effective well and reservoir management.
The increasingly close well spacing at "A" Field has made Seismic Acquisition progressively more challenging. Conversely, it has created an opportunity to utilize dynamic Tubing-Head Temperatures (THTs) for tracking areal thermal conformance over time. For each month in turn an automated workflow:- Grids the monthly THT averages; Integrates the production and injection data, represented as bubble plot overlays; Adds the top reservoir structure from the subsurface model, highlighting structural dip, and fault locations.
Grids the monthly THT averages;
Integrates the production and injection data, represented as bubble plot overlays;
Adds the top reservoir structure from the subsurface model, highlighting structural dip, and fault locations.
Morphing (movie) software then interpolates the monthly images to create a smoothly transitioning "Heat Movie".
The Heat Movie demonstrates the general effectiveness of the Development in terms of warming the reservoir over time. This in turn is reducing the oil viscosity and increasing production. However, it also highlights temperature anomalies that can be linked to geological features such as faults and high permeability layers. Identification of these anomalies may underpin decisions to optimise the thermal development.
In addition to the Movie, time-lapse images can be created for any chosen period. This is similar to 4D Seismic, but more powerful, since the period can be directly linked to significant field milestones, for example equal time periods before and after upgrading the steam generation process.
Proof of Concept was demonstrated in early 2018, and the technique has already been deemed sufficiently mature to utilize it for tracking and managing Thermal Conformance in place of 4D Seismic. This is resulting in annual cost savings of millions of dollars and man-years of staff time.
One potential advantage of 4D Seismic is highlighting vertical conformance. Although this is not possible using THTs alone, at "A" Field the plan is to mitigate this by integrating data from ongoing Distributed Temperature Sensing (DTS) and well temperature surveys.
Regarding applicability, the workflow can be adapted for other objectives, for example creating a movie of surface uplift and/or subsidence integrated with bubble plots of production and injection data, or water breakthrough for wells with downhole gauges, in water flood developments.
In addition to describing the methodology underpinning this innovative approach, this paper will also discuss the vision for further improving the workflow and expanding the functionality.
Shaqsi, Khadija Al (Petroleum Development Oman LLC) | Alwazeer, Abdullah (Petroleum Development Oman LLC) | Belghache, Abdesslam (Petroleum Development Oman LLC) | Mawali, Shaikha Al (Petroleum Development Oman LLC) | Sawafi, Marwan Al (Petroleum Development Oman LLC) | Aulaqi, Talal Al (Petroleum Development Oman LLC) | Bulushi, Badriya Al (Petroleum Development Oman LLC) | D'Amours, Kevin (Petroleum Development Oman LLC) | Yahyai, Ahmed Al (Petroleum Development Oman LLC) | Yazidi, Rashid Al (Petroleum Development Oman LLC) | Hilali, Ali Al (Petroleum Development Oman LLC) | Zaabi, Yousuf Al (Petroleum Development Oman LLC) | Hinai, Jaifar Al (Petroleum Development Oman LLC) | Mujaini, Rahima Al (Petroleum Development Oman LLC) | Gheithy, Ali Al (Petroleum Development Oman LLC) | Bettembourg, Solenn (Shell Kuwait LLC)
This paper describes how the deployment of multiple Lean projects by Petroleum Development Oman's Thermal Well and Reservoir Management (WRM) team has resulted in significant cost savings, in terms of efficiency and oil production.
WRM teams are an integrated group within production assets, comprising of petroleum, process engineers, operations staff and well services. Supported by data acquisition and interpretation, the teams are responsible for operating and optimizing the field.
Historically, Petroleum Development Oman's Thermal WRM team faced some challenges such as data access and activity processing including pattern reviews, Cyclic Steam Stimulation (CSS) planning, business planning and operational routine activities such as fluid levels. In addition, key surveillance activities suffered from delays and data interpretation inaccuracy. The above resulted in significant time inefficiencies and deferred oil production.
The continuous improvement initiatives started in 2015 with a particular focus on improving thermal WRM process. A deployment plan was created starting with identifying the need and clarifying the required steps to earn the Lean status as defined in PDO. Lean Management System (LMS) was defined followed by awareness sessions. These initiatives resulted in the identification of many opportunities for continuous improvement and Lean initiatives.
Multiple improvement areas were identified against a set of measured baseline conditions. The following projects were selected for Lean: Integration pattern reviews improvements. CSS optimization by monitoring key reservoir management indicators. Reduction well intervention cycle time in CSS. Exception based automation of reservoir surveillance tools. Visualization of CSS workflow and efficiency enhancement. Production forecast automation. Automation fluid level above pump for well optimization.
Integration pattern reviews improvements.
CSS optimization by monitoring key reservoir management indicators.
Reduction well intervention cycle time in CSS.
Exception based automation of reservoir surveillance tools.
Visualization of CSS workflow and efficiency enhancement.
Production forecast automation.
Automation fluid level above pump for well optimization.
Four of the above projects were successfully completed in 2016 and 2017, with the remaining were completed in 2018. Below are highlights of implementing Lean projects in PDO: Estimated 70% manpower time saving. Approximated 5% incremental oil gain. Anticipated 42% reduction in unscheduled deferment. Confirmed 80% waste reduction in overall forecasting, CSS workflow and steam flood monitoring process. Eliminated the need for manual fluid level shots, reduced HSE exposure due to travel.
Estimated 70% manpower time saving.
Approximated 5% incremental oil gain.
Anticipated 42% reduction in unscheduled deferment.
Confirmed 80% waste reduction in overall forecasting, CSS workflow and steam flood monitoring process.
Eliminated the need for manual fluid level shots, reduced HSE exposure due to travel.
Improved tracking of CSS activities reduced operational errors. A thermal economic dashboard was also introduced to rapidly identify sunk costs, minimize Unit Technical Cost and improve Cash Flow.
Thermal EOR projects are technically and economically challenging projects. Improving the geological understanding and implementing these geological concepts into the static model were key to increase the robustness of, not only the geological model but also of the dynamic simulation.
The initial believe was that fine grained and mm scale laminated sediments act as vertical baffles for the steam distribution. The fine grained sands were low in permeability and the lamination were further reducing the vertical permeability. Grain size had the main impact on permeability and grain size was correlated with V-shale. Then, V-shale was used as a proxy for grain size and was integrated into a V-shale base porosity-permeability transformation.
After modeling the baffles explicitly, it was shown that against the initial belief, the main control on fluid flow was not a patchy baffle distribution. Instead the reservoir was overall reduced in vertical permeability. A lager impact had the V-shale base poro-perm transform, predicting an order of magnitude permeability range for a given porosity. Reducing the impact of the facies also reduced overall the uncertainty and improved the predictive power of the models. This in turn, helped to take development decisions with much higher confidence.
A major Permo-Triassic carbonate gas reservoir that was deposited on a very broad, shallow, restricted marine platform across the Arabian plate consists of interbedded carbonates and evaporites with episodes of minor windblown clastic influx. The reservoir has several characterization challenges including: heterogeneous mineralogy, rapidly varying sediment layers, constrained grain sizes (indicating very low initial energy differentiation in the sediments constituting the facies) combined with subsequent lateral reworking in the transgressive systems tract, thin parasequences, aerial exposure, lateral reworking and multiple episodes of diagenesis. During more than three decades of production, many studies have attempted to characterize this formation for the optimization of the gas production. Matching the production history and predicting the dynamic behavior of current and planned wells in this reservoir is still a difficult task. Highly variable mineralogy and pore types suggest significant vertical and lateral variations in the reservoir property parameters used to determine reservoir gas saturation and productivity. This work focuses on the integration of the detailed depositional facies model with the Pressure Depletion Petrophysical Rock Types (PDPRT) developed by Clerke and Al-Nasser to improve the reservoir performance prediction.
We use a comprehensive (~1000 feet of core covering ~220 depositional para sequences) set of cored wells and a carefully designed core analysis program to develop a database defining important links between facies and PDPRT's. Of the nine depositional facies defined by sedimentologists, five of them have reservoir potential. The results from this thorough program improves the hydrocarbon saturation calculation and the prediction of reservoir dynamics during pressure depletion. This state of the art characterization workflow includes: core description, thin section examination, petrographic analysis, mineralogy at multiple scales, routine core analysis (RCA) at multiple overburdens, mercury injection capillary pressure (MICP) measurements, porous plate data, and Archie parameter determination.
The Pressure Depletion Petrophysical Rock Types (PDPRT)-pore types for the highly variable carbonate lithology are defined using a two stage classification: first on the continuous mineral framework defined from QEMSCAN (Quantitative Evaluation of Minerals by Scanning Electron Microscopy) mineralogy images and then by the dominant pore type using quantitative petrographic data. These PDPRT's-pore types are also completely characterized by their Thomeer pore system parameters obtained from analyzed MICP data. These data define the pore throats of the rock-pore types in detail and with greater petrophysical rock type contrast than the conventional poro-perm method.
We obtain and also present here the significant links discovered between the depositional facies and our petrophysical rock-pore types. Integrating depositional (and depositionally related diagenetic) patterns with petrophysical rock typing greatly improves the reservoir dynamics prediction. Additional improvements come from the observation that early anhydrite reservoir pore cements result from the vertical juxtaposition of cycle-capping, tidal-flat facies with reservoir bodies in underlying parasequences. These links significantly improve reservoir model water saturation calculations and permeability predictions, which then leads to improved well placement, reduced CAPEX, production optimization and improved OGIP estimates.
This manuscript describes a novel approach to monitor water flood front movement using Proximity Sensing in conjunction with contrast agents. Our technique exploits the presence of resistive layers between reservoirs, which act as a transmission line for electromagnetic signals, to achieve increased propagation range. This work focuses on numerical simulations to evaluate the potential of this approach to monitor water movement in the reservoir under different conditions.
A series of 2D axisymmetric numerical simulations were conducted to assess the potential of Proximity Sensing to monitor moving fronts of labeled brine as well as to detect isolated pockets of brine labeled with contrast agents. The study was conducted using layered models that resemble a resistive seal bounded by reservoirs saturated with brine or brine and contrast agents. The effect of magnetic permeability (μ) on signal travel time and amplitude is reported and compared to the effect of electric permittivity (ε).
The results show that Proximity Sensing is a suitable technique to detect changes in the μ of reservoirs adjacent to resistive seals. Therefore, our approach can be used in combination with contrast agents, such as Magnetic NanoMappers, to monitor water flood front movement in the reservoir. In addition, this technique can be used to detect isolated pockets of labeled brine, which suggests that injection of slugs of labeled water would be enough for field applications. The observed effect of μ on signal travel time is similar to the trend observed when the electric permittivity of the bounding reservoirs is changed. A significant difference is that increasing μ of the bounding reservoirs appears to reduce signal amplitude while increasing ε has the opposite effect. This result was unexpected and requires further simulations and experimentation to validate this behavior.
Proximity Sensing offers a novel approach to address the challenge of electromagnetic propagation in conductive media and paves the way for the development of refined techniques that provide reservoir saturation and water flood front monitoring capabilities with greater resolution.
Al Kalbani, M. (Medco Oman LLC) | Al Saadi, H. (Medco Oman LLC) | Mirza, M. (Medco Oman LLC) | Kurniadi, S. D. (Schlumberger) | Hilal, Ahmed (Schlumberger) | Al Kalbani, M. S. (Schlumberger) | Kelkar, S. (Schlumberger)
When oil prices are low, the oil industry tends to reduce its capital expenditure to fund new projects, such as exploration and development projects. The reduction in exploration activity ultimately affects the operators’ reserve balance. These conditions push each operator to use innovative solutions to increase reserves. Hydraulic fracturing is considered one of these solutions because it enables revisiting the possibility of producing an uneconomic reservoir with the existing wells. One reservoir that is being reevaluated is the Karim formation located in the Karim Small Fields (KSF), the Sultanate of Oman.
The Karim formation is divided into three segments, with the most promising being the Lower Khaleel, which was initially considered uneconomic to develop. The Khaleel is a sandstone formation at approximately 2000 m depth, with fair porosity and permeability and containing moderate-viscosity oil. The current recovery factor in the Khaleel is still less than 5%, and it is not considered for a full-field development plan due to low production results.
Because the wells drilled in the Khaleel formation were not prepared for a fracturing operation, several challenges appeared during early review, including the well trajectory and azimuth, completion condition, intervention strategy, data availability, and reservoir understanding on the formation water source and its connection to the Khaleel. The project was separated into three phases: feasibility and technical study phase, fracturing trials and evaluation phase, and fracturing understanding and optimization phase. Results are available for the first two phases, and a plan has been formulated for the third phase.
The feasibility and technical study involves understanding the geology, geomechanics, and petrophysics of the wells in which a fracturing operation was performed previously in a different formation. This study was followed by a candidate selection step involving more than 10 existing wells. The candidate selection process used a novel workflow to incorporate all the challenges into the selection criteria. Results of the candidate selection phase led to selection of the top three wells for fracturing operations in the Khaleel formation. Two out of three wells were selected for hydraulic fracturing treatment in the initial trial phase. Observations and results have been obtained from the execution of the trial hydraulic fracture jobs in these wells.
The A East Haradh formation contains a 200-m-thick oil column of highly viscous oil, with viscosity ranging from 200 to 400,000 cp. Because of the high viscosity, first production was considered possible only by the use of thermal enhanced-oil-recovery techniques, starting with cyclic steam stimulation (CSS). This paper presents key learnings derived during this initial-operations phase of CSS in the A East Field, including key trial results on different well completions and artificial-lift systems. In light of the results of a new geochemical characterization study of the crude extracted from a core, cold production was deemed feasible in the crestal area of the field. Viscosities at the top of the Haradh were estimated at 200 cp, lower than previously thought, and progressing cavity pumps (PCPs) were installed in 32 wells to start a cold-production phase.
Understanding and prioritizing water management is key for exploration-and-production operators, not only in terms of reducing overall cost and capital expenditures but also as a means of mitigating operational risk, complying with changing regulatory requirements, and addressing environmental concerns. Water-management decisions within shale oil and gas production fall into three primary categories: water acquisition, water usage within hydraulic-fracturing operations, and the disposal of produced and flowback waters from drilling and production. Shale-fracturing flowback refers to the portion of injected hydraulic-fracturing fluids that returns to the surface before and during initial production. The large quantities of flowback and formation water generated during the fracturing process must be treated before recycling, beneficial reuse, or disposal. Shale produced water typically refers to water produced during the production phase of the shale wells in the longer term and has significantly lower flow rates and more-consistent quality than flowback water.
Excessive water production from hydrocarbon-producing wells can adversely affect the economic life of the well. The major challenge for water control in carbonate reservoirs is polymer bonding to the rock surface. Most commercial products are designed for sandstone formations, and most polymers will not strongly adsorb to carbonate reservoirs. A new water-shutoff polymer system has been developed for carbonate formations and shows great stability. The objective of the project was to develop additives to be used as a smart sealant that can be used to control unwanted water production.