With the help of artificial intelligence, BP says it needs 40% fewer workers to keep its natural gas flowing in Wyoming. A visitor to one of BP’s natural gas fields in Wyoming a few years ago might have noticed an odd sight: smartphones in plastic bags tied to pumps with zip ties. This was an early test of a multistate initiative by the oil giant to link a network of Wi-Fi sensors to an artificial intelligence (AI) system—one that now operates the Wamsutter field in Wyoming with far less human oversight than before. AI has come to the oil patch, accelerating a technical change that is transforming the conditions for the oil and gas industry’s 150,000 US workers. Giant energy companies like Shell and BP are investing billions of dollars to bring artificial intelligence to new refineries, oilfields, and deepwater drilling platforms.
Rathnaweera, Tharaka D. (Monash University /Nanyang Technological University) | Gamage, Ranjith P. (Monash University) | Wei, Wu (Nanyang Technological University) | Perera, Samintha A. (The University of Melbourne) | Haque, Asadul (Monash University) | Wanniarachchi, Ayal M. (Monash University) | Bandara, Adheesha K. (Monash University)
Over the last several decades, many studies have generated a large amount of proppant performance data, but these studies have only focused on proppant conductivity, with no attention to how proppant mechanical properties vary under loading conditions. The impact of mechanical behaviour on proppant performance can only be fully understood by the combined investigation of micro-structural and mechanical changes with increasing loading. Therefore, this study aims to identify such micro-structural behaviour, and in particular the impact on proppant mechanical properties. Proppant samples were tested under one-dimensional compression loading using high-resolution X-ray CT scanning technology. The reconstructed images taken at different load stages were analysed to capture the micro-structural behaviour and finally correlated with the mechanical behaviour of the proppant.
According to the results, there are significant micro-pore voids inside the proppant mass. When the proppant has a higher degree of porosity, there is a considerable reduction of the compressive strength which is not favourable for hydro-fracturing treatment designs. Moreover, it is clear that the brittleness of the proppant decreases with increasing porosity, as its Young’s modulus reduces with increasing pore voids. Therefore, it is important to have high manufacturing standards to achieve effective proppant performance at great depths. The micro-structural behaviour under increasing loading was investigated by performing comprehensive CT image analysis using Drishti software. According to the results, under compressive loading, proppants cleave and generate large fragments like a flower, and this happens suddenly and quite violently through the material. Interestingly, post-failure analysis revealed that the failure mechanism of a single proppant consists of three major stress levels, where initially proppant fails at a high stress level and gains some crushing-associated strength at later stages.
Unconventional oil/gas production has recently attracted the research community due to the uncontrollable increasing demand for primary energy sources (Perera et al., 2016; Wu et al., 2017). Since this method provides a good solution to energy scarcity, over the last several decades, the industry has tried to enhance the production rate, mainly focusing on production enhancement techniques which can be effectively used in the energy extraction from sub-surface geological formations. Of the various options, hydraulic fracturing is one of the best ways to enhance oil/gas extraction, as it increases the formation’s permeability, allowing easy movement of the extracted oil/gas towards the production well (Rutledge and Scott, 2003; Orangi et al., 2011; Vengosh et al., 2014; Wanniarachchi et al., 2015). However, this process may be jeopardised due to the high stress levels acting on the formation at great depths (both vertical overburden and confining pressures). One possible consequence is re-closure of the fracture network under downhole stress conditions, which severely affects the post-fracturing production. Such issues can negate the use of proppant as a hydraulic fracture treatment method where proppants injected with the fracturing fluid prop the fractures, withstanding the fracture-closure stress (Wanniarachchi et al., 2015). Although the proppant gives a reliable solution to overcome this issue (propping the fracture network), sufficient closure stress can cause mechanical failure of the proppant, changing the fracture conductivity, causing re-closure of the fracture network, and altering the bulk properties of the proppant pack, which can negatively influence oil/gas extraction. Therefore, it is important to understand the mechanical behaviour of proppants under downhole stress conditions before injecting proppant with the hydro-fracturing fluid.
There has been recognition in the oil and gas and mineral extractive industries for some time that a set of unified common standard definitions is required that can be applied consistently by international financial, regulatory, and reporting entities. An agreed set of definitions would benefit all stakeholders and provide increased - Consistency - Transparency - Reliability A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) jointly approved the "Petroleum Reserves Definitions." Since then, SPE has been continuously engaged in keeping the definitions updated. The definitions were updated in 2000 and approved by SPE, WPC, and the American Association of Petroleum Geologists (AAPG) as the "Petroleum Resources Classification System and Definitions." These were updated further in 2007 and approved by SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). This culminated in the publication of the current "Petroleum Resources Management System," globally known as PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and has been used by the US Securities and Exchange Commission (SEC) as a guide for their updated rules, "Modernization of Oil and Gas Reporting," published 31 December 2008. SPE recognized that new applications guidelines were required for the PRMS that would supersede the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. The original guidelines document was the starting point for this work, and has been updated significantly with addition of the following new chapters: - Estimation of Petroleum Resources Using Deterministic Procedures (Chap.
Huang, Qingfeng (Abu Dhabi Marine Operating Company) | Arii, Hiroaki (Abu Dhabi Marine Operating Company) | Sadok, Abdel Aziz Ben (Abu Dhabi Marine Operating Company) | Baslaib, Mohamed A. (Abu Dhabi Marine Operating Company) | Sasaki, Akihito (Abu Dhabi Marine Operating Company)
Infill drilling has been recognized as a common practice to accelerate oil production and increase ultimate recovery. Infill drilling can be performed under different drive mechanisms (primary, secondary and tertiary). With a certain history of development, many oil fields have become mature to some extend with waterflood. In order to have a sustainable corporate development plan, pattern flood towards further EOR is considered. Nonetheless a tertiary process as a whole project involves massive investment with high risks and uncertainties. If incremental oil can be recovered via infill drilling as a transition, the investment can be partially offset and justified. Infill oil producers as components of pattern flooding can be accelerated while pattern water injectors can be scheduled in a latter phase.
Two main approaches are used in the determination of infill potential. The first one uses empirical techniques to determine infill wells number and spacing based on volumetric calculation of oil in place. It ignores impact of reservoir heterogeneity and continuity. The second approach relies on numerical simulation coupled with optimization algorithms. Based on the second approach, this paper presents a new one that looks at the remaining mobile oil distribution at the time of infill drilling, and locates the optimum pattern configurations whose centers have the maximum sum of stacked mobile oil thickness of each pattern. Each square pattern has only one oil producer centered without corner water injectors.
An automated algorithm has been generated to identify infill potential and locations. First, the remaining stacked mobile oil distribution is calculated; second, multiple average-spacing pattern realizations are placed on the field, and only one realization is chosen since it has the highest value of summing mobile stacked oil thickness; third, remove infill wells which have nearby existing oil producers in the pattern area; then, select perforation intervals with a certain criteria to avoid early water/gas breakthrough; after that, an automatic schedule of infill wells is output for simulation run to screen potential infill wells having minimum impact on the existing wells.
This infill drilling approach identifies potential pattern oil producers to recover mobile oil, sustain the production plateau and increase oil recovery, prior to planning pattern water injectors. In offshore field, tower slots are limited, so some infill wells can be utilized to workover/sidetrack future inactive wells to save slots. Infill wells can be coupled utilizing conventional completion strategy to minimize wells count. These wells act as a smooth transition to future pattern configurations towards further EOR to recover remaining oil.
For the first time, this paper demonstrates a novel approach of determining infill locations by chasing in-situ stacked mobile oil thickness at the specified time step. An automated program is generated to efficiently identify infill wells at any time step. A complete workflow of infill drilling and transition to pattern flood is prepared for a full image. This process also suits both new and mature field. Pattern flood is accelerated by drilling infill oil producers and followed by water injectors.
Sultan, Mir Asif (Abu Dhabi Company for Onshore Petroleum Operations Ltd) | Ali, Muhammad (Abu Dhabi Company for Onshore Petroleum Operations Ltd) | Hegazy, Gehad Mahmoud (Abu Dhabi Company for Onshore Petroleum Operations Ltd)
One of the main challenges in exploration / appraisal phase is to measure the reservoir pressures and sample down-hole single phase fluids to identify the fluid types in tight layers (permeability <1md). This challenge escalates when multiple reservoirs are exposed in same open-hole with varying differential pressures across them. A novel wireline formation tester (WFT) technique was applied in an open-hole condition to collect in-situ representative fluid samples faster and cost effectively. It also significantly reduces the risks associated while sampling across multiple reservoirs in comparison to the conventional techniques.
Conventional approach of using dual packer module requires longer set-unset time as well as pumping out the trapped volume between the packers before receiving fluid from the formation. On the other hand, the probe module is more effective for sampling in high permeability layers. In tight reservoirs, the fluid sampling is very challenging due to low formation withdrawal rates, high drawdown and elongated station times. These challenges were overcome with a radically designed WFT that utilizes a 3D elliptical probe module with an optimum reservoir contact area. These probes enable circumferential flow from the formation with a faster cleanup process and hydrocarbon breakthrough.
The new sampling technique showed an improvement, over the conventional methods in several aspects: (1) Tight zone pressures are obtained faster with lower supercharging effects. (2) In-Situ representative fluid samples are acquired in tight reservoirs above saturation pressure enabling proper fluid characterization PVT studies. (3) Stationary times during sampling are reduced due to negligible trapped volume. (4) Set and retract timing is shorter so that a new sampling method of retract-move-reset is developed to minimize the mud invasion between multiple settings. (5) Reduces the differential sticking risk in longer operations with multiple reservoirs exposed in the same open-hole. (6) Minimizes the sampling runs resulting in significant cost saving. Logging operation proved to be successful with the new sampling method by acquiring representative fluid samples in tight formations, which was not possible earlier.
This paper describes a case history and recent achievements made in acquiring representative single phase fluid samples in tight reservoirs, overcoming the challenges and risks associated with conventional sampling techniques.
Merletti, G. (BP) | Gramin, P. (BP) | Salunke, S. (BP) | Hamman, J. (BP) | Spain, D. (BP) | Shabro, V. (BP) | Armitage, P. (BP) | Torres-Verdin, C. (The University of Texas at Austin) | Salter, G. (Core Laboratories) | Dacy, J. (Core Laboratories)
Tight-gas reservoirs undergo unique and often complex burial, diagenetic, structural, fluid pressure and saturation histories. Porosity alteration from compaction, cementation and grain leaching can continue after hydrocarbon charge, further complicating saturation modeling. Many reservoirs have gone through multiple cycles of drainage and imbibition, often at different stages on the diagenetic pathway to current pore-scale morphologies. The understanding of saturation distribution and state is not only desired but required for predicting reservoir performance, estimating realistic recoverable volumes, and optimizing costs for development and production.
The Almond Formation is characterized by three depositional facies associations: shoreface, deltaic and fluvial-coastal plain. These groups are commonly fine grained and well sorted. The differences in pore architecture arise from differences in primary depositional fabric and rock-frame mineralogy and their subsequent diagenetic alteration; yielding predictive trends in porosity-permeability space.
Drainage and imbibition saturation-height models have been developed from core studies and integrated with logs to verify that reservoirs are at primary drainage and to highlight any potential imbibition due to trap tilting or leaking. Centrifuge and multicycle mercury injection data were integrated to produce composite drainage capillary pressure curves. Stressed mercury extrusion tests are commonly used for modeling water saturation through the imbibition process. These tests display no correlation with rock quality at low capillary pressures. To circumvent these problems, mercury extrusion was integrated with maximum-trapped-gas measurements obtained by countercurrent imbibition experiments.
Using the resistivity-derived water saturation model as reference, the free-water level for drainage and imbibition models was optimized by matching saturation-height models in reservoirs free of resistivity shoulder-bed effects. The accuracy of the match in different rock qualities provided insights on the likely saturation state of reservoirs. Such observations were used to develop successful interpretations of the special distribution of free-water level, reservoir architecture, and hydrocarbon charge.
Merletti, G. (BP) | Gramin, P. (BP) | Salunke, S. (BP) | Hamman, J. (BP) | Spain, D. (BP) | Shabro, V. (BP) | Armitage, P. (BP) | Torres-Verdin, C. (The University of Texas) | Salter, G. (Core Laboratories) | Dacy, J. (Core Laboratories)
Tight-gas reservoirs undergo unique and often complex burial, diagenetic, structural, fluid pressure and saturation histories. Porosity alteration from compaction, cementation and grain leaching can continue after hydrocarbon charge, further complicating saturation modelling. Many reservoirs have gone through multiple cycles of drainage and imbibition, often at different stages on the diagenetic pathway to current pore-scale morphologies. The understanding of saturation distribution and state is not only desired, but required for predicting reservoir performance, estimating realistic recoverable volumes, and optimizing costs for development and production.
Three depositional facies groups were interpreted in the Almond formation. The non-marine facies (fluvial and coastal plain) is a sublitharenite typically with 6-9% primary intergranular porosity, 3-5% secondary intragranular porosity and limited authigenic and carbonate cement (6-16%). The delta facies is a litharenite with 25-40% lithics, <4% primary intergranular and 5-10% secondary intragranular porosity and moderate authigenic and carbonate cement (7%). The shoreface is a litharenite with 16-24% lithics, 6% primary intergranular porosity and 3% intragranular secondary porosity and significant authigenic and carbonate cement (16%). These groups are commonly fine grained and well sorted. The differences in pore architecture arise from differences in primary depositional fabric and rock frame mineralogy and their subsequent diagenetic alteration; yielding predictive trends in porosity-permeability space.
Drainage and imbibition saturation-height models have been developed from core studies and integrated with logs to verify that reservoirs are at primary drainage and to highlight any potential imbibition due to trap tilting or leaking. Centrifuge and multi-cycle mercury injection data were integrated to produce composite drainage capillary pressure curves. A Thomeer saturation model was used to fit parameters such as entry pressure, geometric factor and irreducible water saturation to the capillary pressure tests. These parameters are commonly correlated to porosity and permeability through discrete petrophysical rock types. We found better correlations when parameters are correlated by depositional and diagenetic facies as a continuum across all rock qualities.
Stressed mercury extrusion tests are commonly used for modelling water saturation through the imbibition process. These tests display no correlation with rock quality at low capillary pressures. To circumvent these problems, mercury extrusion was integrated with maximum trapped gas measurements obtained by counter-current imbibition experiments. As trapped gas saturation showed a scattered distribution, data were investigated by aspect ratio estimates and secondary/total porosity ratio from thin-section petrography. In addition to the trapped gas saturation, geometrical factor and initial water saturations were used to fit a Brooks-Corey model.
Using the resistivity-derived water saturation model as reference, the free water level for drainage and imbibition models was optimized by matching saturation-height models in reservoirs free of resistivity shoulder bed effects. The accuracy of the match in different rock qualities provided insights on the likely saturation state of reservoirs. Such observations were used to develop successful interpretations of the special distribution of free-water level, reservoir architecture, and hydrocarbon charge.
This paper presents the mathematical basis for a new and cost effective method to estimate reservoir pressure and effective water permeability in low permeability reservoirs. This method, called Baseline/Calibration, has been successfully tested in the Wamsutter field. This approach, which is an alternative to time-consuming DFIT tests and conventional pressure buildup tests, requires injection of water in multiple short stages. Sandface pressure and flow rate are analyzed to estimate reservoir pressure and permeability.
We derived analytical expressions which provide a mathematical basis for this method. The analytical formulation assumes piston-like displacement of reservoir fluids with injected water in a water-invaded region and conventional transient flow of gas outside this region.
We validated the analytical model and the proposed test-interpretation technique with a numerical simulation model. In addition, we analyzed flow rate and pressure data from a field trial performed in the Almond formation of the Wamsutter field. The results of numerical simulation and the field trial of this method verified that our method accurately determines reservoir pressure with short injection tests.
Measurements of reservoir pressure and in-situ reservoir permeability are important for variety of reasons including estimation of ultimate recovery, production forecasting, and optimization of depletion planning. However, conventional well tests methods, another potential source of these properties, are often impractical in unconventional reservoirs because of the long shut-in times required.
Exploration of the Palaezoic tight gas sands has been ongoing in Abu Dhabi since the early 1980s. The first discovery of gas in this formation dates back to this period; however commercial rates were not proven due to mechanical issues and the overall tight nature of the Pre-Khuff clastics. This formation is not only of interest as a source of gas, but also because gas shows and production from this formation have shown to be free of hydrogen sulphide.
Many wells in the Abu Dhabi Pre-Khuff have resulted in good gas shows while drilling, but did not produce. The poor production test results are not surprising if we consider formation damage the low permeability of the reservoir as regional experience has shown that commercial production rates are only achievable through the application of hydraulic fracturing.
Hydraulic fracturing in the Abu Dhabi Pre-Khuff formation is not without its challenges. The depth of this target creates a high pressure and high temperature environment which requires special equipment and technologies. The geomechanical properties and behavior of this formation are largely unknown in the Abu Dhabi region. In other parts of the Arabian Plate, this formation is known to be a complex geological environment with high fracture gradients, the poor consolidation and a high risk of poroelasticity. The aforementioned attributes make the Pre-Khuff formation a challenge to successfully fracture stimulate.
In a recent Pre-Khuff exploration well, hydraulic fracture stimulation was successfully implemented as part of the completion strategy. This new technique resulted in the successful production test of a Pre-Khuff target at commercial gas rates. In this paper we will show how the integration of petrophysical data, core data, geomechanical interpretations, lab/fluid testing and fracture diagnostics were used to design and optimize the hydraulic fracturing treatment. We highlight key technical risks and challenges encountered during the preparation, design, execution and evaluation phases of this operation and demonstrate how these risks were mitigated and the challenges overcome.. Finally, we will discuss how these methods and workflows can be applied for the improvement and optimization of future Pre-Khuff wells.
Viscoelastic surfactant (VES) fracture fluids were developed as a nondamaging alternative to conventional polymer-based fluids. However, the viscosity performance of typical VES fluids is dramatically reduced at high temperature. Therefore, these fluids are typically limited to treat relatively low-temperature formations unless foamed with nitrogen or carbon dioxide. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, combination of rotational and oscillatory measurements to determine the fluid viscous and elastic properties can better predict whether the fluid can be applied successfully in the field.
The present study was conducted to introduce a new Gemini VES system that can gel and maintain useful viscosity up to 275°F, which can provide additional downhole benefits. Dynamic and static proppant settling tests were conducted using a high-pressure/high-temperature visualization cell to confirm the effect of elastic properties of this fluid on proppant settling. Finally, proppant settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations.
Experimental results show that the surfactant gel behaved as an elastic material (elastic regime), where the elastic modulus (G') was dominant over the viscous modulus (G”) during the tested range of frequency. This behavior gives perfect proppant transport properties. At temperature less than 225°F, Values of G' were independent of the frequency and/or shear rate values, while G” increased with increasing frequency and/or shear rate. At higher temperature, both G' and G” increased with increasing frequency and/or shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The addition of an internal liquid breaker increases the viscous regime with time and temperature. When elastic regime dominates, 100% proppant suspension was confirmed for at least two hours at static and dynamic conditions and temperatures in the range of 75 to 250°F.