We present a novel framework for generating reduced-order models that combines agglomeration of cells from existing high-fidelity reservoir models and flow-based upscaling. The framework employs a hierarchical grid-coarsening strategy that enables accurate preservation of geological structures from the underlying model. One can also use flow information to distinguish regions of high or low flow, and use this division, or other geological or user-defined quantities, to select and adapt the model resolution differently throughout the reservoir. Altogether, the framework provides a wide variety of coarsening strategies that allow the user to adapt the reduced model to important geology and explore and identify the features that most impact flow patterns and well communication. By preserving these features, while aggressively coarsening others, the user can develop reduced models that closely match an underlying high-fidelity model. Various types of simple flow diagnostics based on time-of-flight and volumetric well communication are used to predict the accuracy of the resulting reduced models.
In this paper, we systematically apply this framework to the Great White Field, but also present results from other real or synthetic models, to demonstrate the asymptotic scaling of accuracy metrics with coarsening levels. Our aim is to identify and illustrate best practices when designing and improving coarsening strategies that can guide future applications of the framework to other reservoir models. We also discuss practical limitations when applying the framework to new simulation models where flow regimes or geologic features may differ.
Recent mooring research indicates that fiber ropes with higher strength and higher stiffness would benefit floating offshore platforms in water depths beyond 2000 meters in terms of reduced offset and reduced weight in comparison with polyester rope mooring. More advanced fibers with high strength and high stiffness are also entering into market. The industry has used high strength and high stiffness ropes for temporary moorings and mobile offshore drilling unit moorings. However, high strength and high stiffness fiber ropes have not yet been used for permanent moorings. This paper summarizes studies conducted by the industry on the high strength and high stiffness fiber ropes. An overview is provided for the existing research results, testing conducted, application guidelines, rope qualification processes, project experience, lessons learnt and the challenges of using high strength and high stiffness ropes for permanent moorings. Based on the industry experience of using polyester rope for permanent mooring and knowledge gained on high strength and high stiffness rope, this paper provides recommended assessments that could facilitate the application of high strength and high stiffness ropes for permanent deepwater moorings.
Morrow, Timothy (ADNOC-Offshore) | Al-Daghar, Tariq (ADNOC-Offshore) | Troshko, Andrey (ExxonMobil Upstream Research Company) | Schell, Caroline (University of Tulsa) | Keller, Michael (University of Tulsa) | Shirazi, Siamack (University of Tulsa) | Roberts, Kenneth (University of Tulsa)
The long-term development plan for a giant oil field offshore Abu Dhabi calls for new extended reach wells drilled from artificial islands. The existing wells in this field have historically suffered from inorganic sulfate-based scale deposition in the production tubing which is mitigated by periodic scale inhibition squeeze treatments. The new extended reach wells will have more sophisticated lower completions, including limited-entry liners (LELs) and inflow control devices (ICDs) with external debris barriers. It is currently planned to mitigate inorganic scale in these wells with periodic coiled tubing or bullhead scale inhibition squeeze treatments, which are anticipated to be more challenging and costly due to the extended reach. It is unknown as to whether these types of completion equipment are susceptible to scale deposition or how much scale deposition can be tolerated before well productivity is impacted. Knowledge of the rate of scale buildup on ICDs and LELs versus the volume of water produced through the devices is an important factor for choosing the optimum frequency for scale inhibition squeeze treatments to mitigate scale in these completions while keeping operational costs down. A two-phase laboratory study is currently underway to assess the susceptibility of ICDs to scale deposition. The first phase of the study will focus on the potential for strontium sulfate scale deposition on the debris barrier upstream of the ICD. This paper reports the experimental design and results of laboratory scale deposition experiments on a series of debris barrier test coupons with the goal of estimating the rate of scale buildup on the full-size ICD debris barriers, and the volume of scaling brine that can be produced through the ICD debris barrier (in the absence of any scale inhibitor chemical) without risking significant plugging.
Xiao, Feng (ExxonMobil Upstream Research Company) | Long, Ted A. (ExxonMobil Upstream Research Company) | Velamur Asokan, Badri (ExxonMobil Upstream Research Company) | El-Bakry, Amr (ExxonMobil Upstream Research Company) | Dani, Neeraj R. (ExxonMobil Upstream Research Company) | Holub, Curtis (ExxonMobil Upstream Research Company) | Poole, Stephanie (ExxonMobil Upstream Research Company)
Examples will be presented to show the successful implementation of quantitative slug scanning, gas lift multi-pointing diagnostics, and production surveillance for unstable flows. The slug scanning module supplements the pattern recognition and machine learning features in GLOWTM [
The developed system combines data-driven and physics-based approaches for online advisories, and utilizes a novel history matching procedure to enhance the model's predictive capability for complex well behaviors. In summary, the system provides a comprehensive, robust, and integrated set of tools that meets the surveillance and optimization needs of asset staff.
Chen, Peng (ADNOC Offshore) | Willingham, Thomas (ADNOC Offshore) | Al Sowaidi, Alunood (ADNOC Offshore) | Stojkovic, Dragan (ExxonMobil Upstream Research Company) | Brown, James (ExxonMobil Upstream Research Company)
In the oil industry, oil and gas are usually accompanied with water when they are produced from the subsurface. How to tackle water is one of the major concerns for the field development, especially as fields mature and water production increases. Produced water reinjection (PWRI) has been considered an environmentally friendly way to handle large amounts of waste fluid, though it needs to be carefully designed. In this paper we present a lab study conducted to determine the water specification requirements for reinjecting produced water back into the subject carbonate reservoirs.
The objective of this study is to assess the required produced water quality to maintain matrix injection into the targeted reservoirs. The assessment includes (1) evaluation of the inorganic scaling potential of water sources (fluid compatibility), (2) core flood tests to quantify the impact of various oil content concentrations of produced water on reservoir performance, and (3) a solids loading core flood test to evaluate the injectivity impact of different filtration sizes and different suspended solid concentrations in the produced water. While the previously published paper (
Produced water (PW) collected from the field was utilized in all stages of this study. Analysis of the composition of the suspended solids in the collected produced water revealed a large amount of iron in the PW’s suspended solids, most likely a corrosion product from the long-distance pipeline between the subject field and the current water treatment and separation facilities. Consequently, the collected produced water’s particle size distribution is inadequate to represent the future reinjected produced water which will come from artificial island wells without going through the pipeline. To replicate the anticipated particle size distribution, filtered produced water was mixed with synthetic solid micro particles according to the particle size distribution measured at the well head and the solids loading specification from the skimmer design to mimic the ‘outlet water’ from the skimmer. The skimmer ‘outlet water’ was then filtered to different sizes, starting with 2μm and relaxing the filtration requirements with each step. To replicate oil carryover, 300 ppm of the field’s oil was added to the sequential filtration stages of the skimmer ‘outlet water’ and was flowed through a preserved core plug of the field’s dominant rock type.
Coreflood results suggest that for particle concentrations which represent the solids loading coming from the designed skimmer (TSS=33mg/L), a surface/external filter cake may form with no significant particle penetration into the rock matrix when filtration size is larger than 2µm. More specifically, particles smaller than 2µm did not contribute to the permeability decline, and most of the permeability decline was caused by a filter cake composed of particles in the 5-10µm range. Particles larger than 10µm do not have a significant effect on the permeability decline, most likely due to their low concentration.
Jabbar, MuhammadYousuf (ADNOC Offshore) | Xiao, Rong (ExxonMobil Production Company) | Teletzke, Gary F. (ExxonMobil Upstream Research Company) | Willingham, Thomas (ADNOC Offshore) | Al Obeidli, Amna (ADNOC Offshore) | Al Sowaidi, Alunood (ADNOC Offshore) | Britton, Chris (Ultimate EOR services) | Delshad, Mojdeh (Ultimate EOR services) | Li, Zhitao (Ultimate EOR services)
A laboratory study was performed to identify a robust chemical EOR solution for a complex low-permeability carbonate reservoir. The study consisted of two phases of work. The first phase included development of a surfactant-based EOR method (
This paper is focused on the polymer EOR evaluation and discusses the extensive evaluation process that was followed. The laboratory study included polymer rheology, thermal stability, and transport tests with a novel pre-shearing method, live-condition core flood tests to evaluate dynamic polymer adsorption and description of key chemical and flow properties, and a history match of the core flood test results. In addition, preliminary simulation studies were performed, which demonstrated the recovery potential of polymer flooding.
Two modified, low-molecular weight HPAM polymers were tested and have suitable viscosifying power in injected seawater (41 g/mL TDS) at 100°C. The long-term thermal stability results showed that only the more salt-tolerant polymer is stable at 100°C and retains >80% of initial viscosity at 300 days. The stable polymer was tested in a series of single-phase core floods to evaluate transport through low-permeability (5-10 mD) reservoir cores at 100°C. A novel pre-shearing method was developed where pre-sheared polymer solution with 30% of its original viscosity (~3 cP) transported without significant plugging. Finally a high-pressure live-oil two-phase oil recovery coreflood in preserved reservoir core was performed. The incremental oil recovery with three PV's of polymer solution injection was approximately 17% OOIP. Pressure drop was 47 psi/ft., ~3-5 times higher than that of waterflood, for the 3 cP polymer solution. The polymer breakthrough times and resistance factor were reasonable with no evidence of plugging or injectivity issues considering permeability and viscosity of fluids. The polymer retention was measured to be 150 ± 50 μg/g rock, which is higher than a traditional HPAM flood in high-permeability sandstone rock.
The laboratory results obtained thus far are promising considering very harsh and challenging reservoir conditions. The study also highlights an "up-scaleable" pre-shearing method for field application. In the simulation study, a sector model with representative geological features was taken from the full-field simulation model. Measured physical properties from the laboratory evaluation were used as input for the polymer flood simulation. Recovery uplift from polymer flood was found to be ~5% OOIP with significant reduction in water production and reasonable chemical utilization of <10 lbs. per incremental barrel. The simulation study demonstrated promising potential of polymer flooding for the targeted reservoir.
Inspection intervals have been long established in some jurisdictions around the world based on an assessment of acceptable risk from experience, judgment, and observations of past damage. In areas that do not have the benefit of decades of experience, the designated inspection intervals may be inheriting intervals from another region of the world, and in doing so, potentially subscribing to inspection interval frequencies that assume less or more risk than has been deemed acceptable in other areas of the world. This study investigates two prototype steel piled jacket platforms subjected to metocean conditions present in several areas of offshore development around the world, with the objective to investigate the relative fatigue performance of the prototype structures in these varied environments. The relative performance of these various locations may lend insight into the implementation of risk-consistent inspection intervals for structural integrity maintenance programs.
Permeability is one of the most important parameters that is required in reservoir simulation, field development, and reservoir management. An innovative permeability derivation method and workflow has been developed using Stoneley wave attenuation mechanism (not Stoneley wave velocity as discussed in some previous studies). The workflow was applied to the sonic waveform data acquired from a vertical well in a giant carbonate field in Middle East. The workflow includes (a) extraction of Stoneley-wave attenuation rigorously from the waveform data, and (b) fast inversion from Stoneley-wave attenuation to permeability.
Validation of the method and workflow were performed by comparing the results with core permeability and MDT mobility data. Results from this application indicate that low-frequency monopole waveforms provide good quality Stoneley wave data, and that Stoneley wave attenuation responds to permeability changes. The Stoneley-wave attenuation log extracted from the low-frequency monopole waveforms shows variability, and the permeability log obtained using the inversion workflow through different reservoir intervals has a good overall correlation with core permeability. The main reservoir interval is over 100 feet thick. Porosities are generally high throughout the interval, but permeabilities vary by several orders of magnitude due to pore type changes. The Stoneley wave attenuation permeability trend corresponds very well to vertical changes in the dominant pore system. Stoneley-derived permeabilities distinguish between microporosity in lower section with permeabilities in 1-20 millidarcy range, and mixed-pores in the upper section with permeabilities in the 10's to 100's of millidarcy range. The sonic permeability is also picking up tight streaks (stylolite zones with cementation) that have low porosity and permeability and can act as flow baffles within the reservoir. These results show that Stoneley wave attenuation is responding to changes in carbonate pore systems, and that Stoneley-derived permeabilities can provide useful permeability estimates in the absence of core data.
Suzuki, Satomi (ExxonMobil Upstream Research Company)
Automated pressure transient analysis (PTA) with real-time data feed from permanent downhole gauge (PDHG) enables continuous monitoring of well and reservoir that facilitates timely surveillance decisions. However, while robust automation of the process is critical to minimize the requirement of manual efforts, a challenge lies in automatic diagnostics of a log-log plot which is often contaminated by non-reservoir response such as wellbore dynamics. We propose a new automatic PTA method to enhance accuracy of diagnostics.
The method utilizes a pattern detection method based on similarity search and automatically identifies sequence of flow regimes, such as radial, spherical or linear flow etc., on a log-log diagnostic plot of pressure and derivative. To discover individual flow regimes, the algorithm scans a window on the plot and finds a pattern that is most similar to a ‘motif’ defined for the flow regime. Such motifs are known for individual flow regimes from analytical models. During the similarity search, the algorithm ensures that the discovered sequence of flow regimes is consistent with the flow scenario anticipated at the well.
The proposed method is implemented in fully automated PTA workflow. First, the system reads PDHG pressure and flow rate at a well. Then, pressure buildup intervals are automatically identified. Subsequently, a log-log diagnostic plot is automatically generated for each buildup and the proposed method is executed. Once a sequence of flow regimes is identified, the algorithm locates a horizontal line over the radial flow regime and calculates permeability, skin and extrapolated pressure p*. For horizontal wells, effective completion length is also computed by locating a half slope line on the linear flow regime. For hydraulically fractured wells, fracture length or fracture conductivity is estimated from the linear or bi-linear flow regime. The results are written on output files or to a database together with identified flow regimes visualized on plots for the review of reservoir engineers. The method is tested on oil producers with high water cut where significant fluid segregation or crossflow is impacting log-log diagnostic plots, as well as gas wells where a pressure leak during buildup is contaminating pressure derivatives. Despite such noise of non-reservoir responses, the proposed method successfully identifies flow regimes on most of buildups and produces PTA results comparable to manual analysis.
Compared to existing automatic PTA methods, such as automatic matching of model response or automatic semi-log analysis of radial flow regimes identified by user-specified criteria, the proposed method is particularly robust to use with pressure data which is significantly contaminated by non-reservoir responses. Such robustness of our method is achieved by a flexible pattern search for individual flow regimes rather than matching an entire model response all together or requiring rules specified by engineers.
One of the primary goals of a 4D marine acquisition is to replicate the source/receiver positions of a previously acquired baseline so as to maximize repeatability. Some of the originally shot lines (often called prime lines) are reacquired to improve repeatability, usually depending on proximity to the prospect/reservoir and the availability of funds. The decision to re-acquire a line or a swath is commonly based on sub-surface coverage (fold) plots, dS (distance between sources) plots and/or dSdR (sum of distance between sources and distance between receivers) plots that are generated onboard as a part of standard QC during a 4D monitor acquisition. This can be quite subjective and expensive since we may end up acquiring more data than necessary.
To address this issue of cost versus data quality for 4D marine streamer monitor surveys, a methodology has been developed to aid decision making for real-time 4D acquisition optimization. This methodology uses redundant information from previous baseline/monitor surveys to help in the decision making of re-acquiring lines for an ongoing monitor survey.
Presentation Date: Tuesday, October 16, 2018
Start Time: 8:30:00 AM
Location: 204C (Anaheim Convention Center)
Presentation Type: Oral