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.
Proximity Sensing was recently proposed as way to simultaneously increase both range and resolution in cross-well EM tomography. The approach is applicable to reservoirs with resistive seals. Earlier reports were based on Finite Element Models (FEM) of layered structures, with dielectric and conductivity contrasts matching those of known reservoirs.
Experimental work, now reported, is consistent with expectations based on FEM simulations. Synthetic layered structures have been investigated using a 1.3 GHz Ground Penetrating Radar (GPR) system. Scaled reservoir model was constructed in a one-meter tank comprising sand with filled with fluids of variable dielectric constant and conductivity. In this system, dry sand, brine-saturated sand and a polymer foam provide a useful mimic for the electrical properties expected for a carbonate reservoir sealed by anhydrite. Water saturated porous media served as model bounding layers in analogy to known geologic structures. Data were recorded in the time domain using EM transients. Observed trends in velocities and amplitude shifts were consistent with FEM models. Interestingly, polarization dependent signal transport first indicated by FEM modeling was supported by these experimental results.
Results to date indicate that greatly increased EM propagation can be achieved through resistive geologic layers than directly through relatively conductive reservoir media. We confirm that these layers act as planar transmission lines and not as waveguides – meaning that there is no hard lower cutoff frequency and longer wavelengths can be used to sense and characterize reservoir fluids proximal to the dielectric channel. The results also confirm that variations in bounding layers modulate the amplitude and velocity of the signal in the dielectric channel and thereby demonstrate concept of Proximity Sensing.
These results support a new technical direction for EM characterization of reservoirs, especially in conjunction with magnetic contrast agents, enabling efficient localization of by-passed oil and mapping remaining oil columns in mature reservoirs.
Long-term petroleum reservoir management ideally optimizes production of oil while avoiding brine production and minimizing well count and complexity. Given imperfect knowledge of reservoir structure, significant inhomogeneity and dynamic multi-phase fluid saturation, this is a difficult and long-standing problem that would greatly reward improved methods for observing the state and structure of the reservoir in near real-time. This is particularly true in the case of mature fields in secondary production on waterflood. Modern reservoir models derived from 3D seismic, well logs and history matching are certainly a vital tool for reservoir management. However, our lack of knowledge about large-scale inhomogeneity, including facture corridors, prevent anticipation of early water breakthrough and bypass of significant volumes of oil. As such, there is a great need for imaging tools that can locate flood fronts, detect bodies of bypassed oil and map the remaining oil column thickness across the entire reservoir with sufficient resolution to guide key management decisions. Naturally, reservoir management would be easy if we had imaging modalities with petrophysical scale resolution (e.g. well logs ∼ 0.1 meter) over geophysical survey scales (e.g. seismic ∼ kilometers). However, imaging resolution requirements that can yield valuable and actionable information is probably much less challenging than that, and depends on direction and scale of the particular field under consideration. For the purposes of this paper, we will assert that for giant and super-giant fields (>> 1 B bbl), imaging modalities with resolution on the order of one meter vertically and up to several hundred meters laterally could respectively determine remaining oil column and flooded/bypassed volumes with sufficient accuracy to greatly improve reservoir management practice and development planning. Historic approaches for generating this kind of actionable information include direct full volume imaging using acoustic and low frequency electromagnetic (EM) probes. A new approach based on indirect EM imaging via Proximity Sensing will be described experimentally here.
ABSTRACT: Geomechanical modeling of a reservoir has a very important role in all parts of a field lifecycle. In this paper, we demonstrate a new method for modeling the distribution of elastic properties in the whole reservoir using the concept of geomechanical units (GMUs). In this study, a GMU is a cluster of Young’s, Bulk and shear modulus, Poisson’s Ratio and unconfined uniaxial strength. To establish these GMUs we used eight wells and the Post-stack seismic data in the field of interest. Dynamic elastic parameters were computed from logging data of mentioned wells. To convert these dynamic parameters to static values, empirical equations were determined in a neighboring field of Salman, in the interval of Kangan and Dalan formations. In the next step, Multi-resolution graph-based clustering was applied to these static elastic parameters to construct five distinct GMUs. For three-dimensional modeling of GMUs, the 3D acoustic impedance model of the field was made by genetic inversion and used as a secondary parameter of Co-kriging. The amounts of elastic parameters of each GMU at the location of well number six in the final 3D model are found to be in good agreement with the known values of this well.
Geomechanics is a petroleum engineering sub-discipline developed to address the mechanical behavior of the reservoir and bounding rocks during exploration and production activities (Zoback, 2010; Aadnoy and Looyeh, 2011). In this regard, Three-dimensional modeling of geomechanical parameters plays a significant role in whole life of a reservoir. These models are used for seismic modeling, interpretation, hydraulic fracture design, assessing borehole stability and stress calculations in geological studies. Therefore, any improvement in one of these momentous applications could lead to better and more sufficient field development plans, at the same time save the considerable amount of money and operation time.
This study employs an efficient approach to construct a 3D reservoir geomechanical model based on the concept of Geomechanical Units (GMUs). A GMU is a single unit for design and modeling purposes. A GMU can be selected from logs, cores, or judgment (Dusseault, 2011). The advantages of GMU use in engineering studies have been discussed by a number of authors including Uwiera et al. (2011) and Nygaard (2010). In this work, a GMU is a set of rock mechanical properties, such as: Young’s modulus, bulk modulus, shear modulus, Poisson’s ratio, and uniaxial compressive strength. These elastic parameters are clustered by using different clustering methods to establish the best GMU. The purpose of using this method is to determine the distribution of elastic parameters in whole parts of the field of study. The Kangan and Dalan formations are the reservoir layers in the field of study. These formations are consisted of carbonate and dolomite (Figure 1).
The ability to accurately map injected seawater in waterflood operations is an essential goal of reservoir monitoring. This capability improves reservoir management practices by helping to delineate the oil-water interface in new wells, locate bypassed oil pockets, minimizing water fingering and proactively enabling identification of early water breakthrough events. Our approach involves loading the injected water with magnetic nanoparticles, called Magnetic NanoMappers (MNMs) to function as electromagnetic (EM) contrast agents. Detection is accomplished by EM means, similar to cross-well and borehole-to-surface EM imaging, but at higher frequencies. The strategy for developing this technology focuses on forward modeling and travel-time tomographic inversion software. We have previously shown in the laboratory — using a reservoir model — that MNMs slow the group velocity of transiting EM signals [
The proposed method relies on the use of natural planar transmission lines present in the carbonate reservoirs of the GCC area. An EM pulse traveling through a relatively non-conductive layer between two more conductive layers, will propagate with relatively low attenuation, and the pulse's travel time will depend upon the electromagnetic properties of the layers above and below. MNMs will provide velocity contrast for EM pulses traveling through regions of the reservoir saturated with MNMs-loaded injection water. Similarly, changes in oil and water saturation will result in changes in travel time. By performing full waveform inversion one would be able to produce a saturation map with higher resolution than conventional cross-well EM methods.
This paper details a series of Finite Element Method (FEM) simulations to investigate the feasibility of the proposed method. The results show that long range EM propagation can be achieved through non-conductive layers, acting as planar transmission lines. In addition, the results show that the pulses are modulated by the EM properties of the layers above and below the transmission line. These results open up a new possibility for long range high resolution saturation mapping using EM means.
Katterbauer, Klemens (King Abdullah University of Science and Technology) | Hoteit, Ibrahim (King Abdullah University of Science and Technology) | Sun, Shuyu (King Abdullah University of Science and Technology)
Increasing complexity of hydrocarbon projects and the request for higher recovery rates have driven the oil-and-gas industry to look for a more-detailed understanding of the subsurface formation to optimize recovery of oil and profitability. Despite the significant successes of geophysical techniques in determining changes within the reservoir, the benefits from individually mapping the information are limited. Although seismic techniques have been the main approach for imaging the subsurface, the weak density contrast between water and oil has made electromagnetic (EM) technology an attractive complement to improve fluid distinction, especially for high-saline water. This crosswell technology assumes greater importance for obtaining higher-resolution images of the interwell regions to more accurately characterize the reservoir and track fluid-front developments. In this study, an ensemble-Kalman-based history-matching framework is proposed for directly incorporating crosswell time-lapse seismic and EM data into the history-matching process. The direct incorporation of the time-lapse seismic and EM data into the history-matching process exploits the complementarity of these data to enhance subsurface characterization, to incorporate interwell information, and to avoid biases that may be incurred from separate inversions of the geophysical data for attributes. An extensive analysis with 2D and realistic 3D reservoirs illustrates the robustness and enhanced forecastability of critical reservoir variables. The 2D reservoir provides a better understanding of the connection between fluid discrimination and enhanced history matches, and the 3D reservoir demonstrates its applicability to a realistic reservoir. History-matching enhancements (in terms of reduction in the history-matching error) when incorporating both seismic and EM data averaged approximately 50% for the 2D case, and approximately 30% for the 3D case, and permeability estimates were approximately 25% better compared with a standard history matching with only production data.
Saudi Aramco Moving Forward on Unconventionals
Trent Jacobs, JPT Senior Technology Writer
With the world’s fifth-largest estimated shale gas reserves, there is great potential for Saudi Arabia to replicate North America’s unconventional growth. Saudi Aramco’s unconventional program became operational in 2013 and the company has been working with major service companies, including Halliburton and Schlumberger, to develop the reserves.
The primary driver is the country’s pressing need to find new supplies of gas to replace the domestically produced crude oil used to generate most of its electric needs, demand that can reach as high as 900,000 B/D in summer. Another major aim is to use unconventional gas to bolster the country’s growing petrochemical industry.
Enhancing Sand Strength for Fracturing Applications
Pam Boschee, Senior Manager, Magazines
Sustaining the fast economic growth in Saudi Arabia requires a ramp up of the gas supply. A strategic objective of Saudi Aramco is exploring and developing deep and unconventional gas reservoirs, many of which are considered extremely tight. These formations need hydraulic fracturing to allow the hydrocarbons to be efficiently produced. Unlike in North America, the infrastructure to commoditize the drilling and production processes is immature in Saudi Arabia. Therefore, many cost-reduction measures have to be exhausted, especially on materials. Proppant is the main material used in fracturing and, therefore, reducing its cost affects greatly the economics of any fracturing operation.
Although the country has abundant natural sand resources, the strength of the sand is insufficient to withstand closure stress in most of the gas reservoirs. New technology can enhance the local sand strength to make it deployable in deep formations with closure stress greater than 10,000 psi.
Competing Companies Building Robots to Place Receivers
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
Autonomous Robotics’ first offering is built around a rounded yellow device that looks like a little flying saucer. It is more of a seismic saucer because it is designed by the UK startup to “fly” from a drop-off point in the water to a designated spot on the seabed, where it will record seismic data until it is ordered to return.
The company was one of two firms displaying flying nodes under development at the recent Society of Exploration Geophysicists (SEG) annual meeting in New Orleans. The other was Seabed Geosolutions, which has been working with Saudi Aramco since 2012 to develop a flying node called Spice Rack.
Flow Sensor Technology Seeks to Replace the Coriolis Meter
Trent Jacobs, JPT Senior Technology Writer
Australian technology developer MezurX is touting its newly introduced flow, density, and mud monitoring system as a significantly better alternative to the widely used Coriolis meter. Using an advanced set of sensors, the X-Omega provides real-time information that can be used on rigs for early kick detection and managed pressure drilling (MPD).
Bruce Henderson, president and CEO of MezurX, claims the technology involves “a completely different way of measuring density and flow” while offering more reliability and a smaller footprint than Coriolis-based systems.And despite the current price environment, Henderson said several service companies and offshore operators are showing interest in the X-Omega system and work has already been awarded. “It’s an interesting time for us,” he said. “I think that during a downturn in the industry, new technology is always attractive to keep costs down and make things more efficient.
Lawrence, David A. (Al Hosn Gas) | Hollis, Cathy (University of Manchester) | Green, David (Badley Ashton & Associates (Currently Weatherford Laboratories)) | de Perière, Matthieu Deville (Badley Ashton & Associates) | Al Darmaki, Fatima (Al Hosn Gas) | Bouzida, Yasmina (Baker Hughes)
The Late Jurassic Arab Formation is being developed in a major gas accumulation located onshore southern UAE. The lower Arab Formation consists of wackestones to mudstones of mid ramp to basinal setting overlain by foreshoal and oolitic grainstone shoal deposits. Despite the number of well penetrations, several published models have been proposed for the palaeogeographic evolution of the shoal complex.
The grainstone-dominated interval comprises skeletal and ooid-rich wackestones and packstones grading upwards into oolitic grainstones interpreted as the result of progradation of foreshoal to ooid shoal environments. A key element to understanding reservoir architecture has been the integration of core descriptions with borehole image logs, permitting recognition and re-orientation of the main bounding surfaces and cross-bedding sets. Existing depositional models for grainstone shoals are highly schematic and not useful for defining reservoir architecture.
Two key surfaces constrain correlation and reservoir architecture: a basal hardground typified by dolomitised burrows and an upper erosion surface which terminates grainstone deposition. Shoal initiation was in the southwest of the study area with progradation of bioturbated foreshoal deposits with isolated planar cross-sets. Tidal reversals become more frequent upwards, with deposition mainly in offshore flood-oriented ooid sand ridges.
The main part of the grainstone interval is dominated by a stacked parabolic sand shoal complex comprising cross-bedded oolitic and skeletal grainstones. Initial primary macroporosity in this facies association is pervasively occluded by calcite cements. Behind the shoal complex, planar laminated oolitic grainstones accumulated in flood-tidal deltas in a broad lagoon. Progressive infilling of the lagoon by sediment supplied from the shoal resulted in basinward (northeasterly) shifting of the shoreline and development of linear beach ridges. Bioturbated to massive grainstones capping shoal complexes are clean and only patchily cemented retaining a well-connected primary macropore network.
Geometries, scales of cyclicity and facies distributions indicate analogs to modern tidally-influenced ooid ridges and parabolic bars of the Bahamian system.
Hu, Jialiang (Abu Dhabi National Oil Company (ADNOC)) | Obaid, Khalid (Abu Dhabi National Oil Company (ADNOC)) | Witte, Johan (Abu Dhabi National Oil Company (ADNOC)) | Mahgoub, Mohamed (Abu Dhabi National Oil Company (ADNOC)) | Neves, Fernando (Abu Dhabi National Oil Company (ADNOC))
Previously, the deep reservoirs of Middle Jurassic (Araej Formation), Upper Permian (Khuff Formation) and pre-Khuff (Berwath Formation) age in a salt-related field offshore Abu Dhabi were interpreted to be uneconomical due to their small GIIP volume which was based on limited data from only one exploration well. However, new geological studies including basin modeling suggest a much higher potential for deep gas in this particular field. In view of the increasing demand for gas in Abu Dhabi, ADNOC has initiated the re-evaluation of a number of deep gas reservoirs using updated geological models, integrating reprocessed 3D OBC seismic and all available well data.
The major challenge in modeling these deep reservoirs is lack of well control. It is challenging to calculate statistically meaningful averages for the lateral variations in reservoir characteristics with high confidence, only based on a few wells. On the contrary, reservoir property-related seismic attributes such as RMS amplitude and acoustic impedance from post-stack inversion of the 3D OBC seismic are laterally continuous datasets, providing the database for lateral statistics. In this study, geostatistics are combined with horizontal variogram modeling based on seismic and vertical variogram modeling based on wells, which bridges the vertical-lateral gap of resolution and continuity between wells and seismic. Variogram maps rather than a single variogram model are calculated from the average seismic attribute maps, which extend statistic control of lateral continuity to 360 degrees. In addition, variograms are mapped for each fault segment separately, which honors the reservoir behavior to the maximum. Statistically, seismic attributes show a similar trend in their probability curves and vertical distribution as reservoir properties calculated from well logs. Therefore the final reservoir property models are built using co-krigging sequential Gaussian simulation with seismic-well combined variograms.
As a result, the new geological model enlarges the area of deep-gas prospectivity and locates the primary deep gas target in the Upper Khuff and pre-Khuff around the crest of this field. The re-calculated GIIP with low, average and high cases now shows an economical gas volume in these deep reservoirs.
This integrated statistics and modeling approach, combining seismic and well data reduces uncertainty in reservoir characterization with limited well data. Considering the good coverage of seismic in Abu Dhabi, this approach can be applied to the other fields with lack of deep well penetrations.
How important is technology to Saudi Aramco’s strategy?
The development and implementation of a globally competitive technology is very important to Saudi Aramco. We believe technology leadership drives continued and future success in the energy sector and is essential to achieving our aspirations to help solve global energy challenges and to stimulate the local knowledge economy.
We have laid the groundwork to create a sustainable competitive advantage through the introduction of a balanced portfolio of technically feasible and commercially viable technology options.
In upstream, the key research domains are reservoir engineering, computational modeling, drilling, production, geophysics, and geology. Research and development activities seek to increase incremental oil recovery from major reservoirs and increase the company’s resource base. Specific technology projects are directed toward increasing exploration probability, reducing finding costs, increasing production reliability, and enhancing cost efficiency.
In downstream, by which we mean everything that takes place above the ground, the key research domains are oil and gas treatment, oil upgrading, chemicals, and network integrity. The downstream research domains are all about maximizing the value from every barrel of oil we produce, which is achieved though innovation in process improvement and production efficiencies in downstream businesses such as chemicals and refining.
In addition, our strategic research domains of carbon management and fuel/ engine technology pursue the long-term sustainability of crude oil as the preferred energy source in the global marketplace.
What are the new technologies being pursued?
Our technology portfolio includes a number of cutting-edge innovations across a range of disciplines, including areas such as advanced materials, robotics, computational modeling, and others.
For example, researchers at our upstream research center are at the forefront of leveraging micro- and nanotechnologies to develop breakthrough technologies to increase oil and gas production.
Specific areas of interest include exploration, drilling, reservoir characterization, mapping and detecting various subsurface fluids, improved/enhanced oil recovery, and production.
Shaikh, Mohammed Razik (Petroleum Development Oman) | Rodriguez, Francisco Alberto (Petroleum Development Oman) | Reiser, Herbert (Shell Development Oman) | De Zwart, Albert Hendrik (Shell Intl EP Co) | Rocco, Guillermo (Petroleum Development Oman) | Al-Shuaili, Khalid Said (Petroleum Development Oman) | Adawi, Rashid (PDO)
A field, located in south Oman, has a compact dome shaped structure with an oil column in excess of 200m. It produces highly viscous hydrocarbon from the fluvial Cambrian Haradh reservoir and represents an opportunity for Thermal EOR development. After an initial phase of steam injection, field data have shown that the response in the trial pattern is not homogeneous. In order to explain these observations a multidisciplinary effort has been undertaken to improve our understanding of the subsurface.
The information acquired in and around the injection area (an inverted 7-spot pattern), include connectivity trends from pressure data, temperature surveys, time lapse seismic, cores and well logs. After 20 months of steam injection a thermal response within the pattern is limited to only one producer well and two observation wells. The time-lapse seismic data is consistent with the field data observed from wells in the northern part of the pattern. The pressure data also indicate a predominant North-South connectivity trend within the pattern.
Four geological scenario models were built to test factors that may impact the understood distribution of temperature resulting from injection. The modelling workflow intends to assess the impact of 1) the internal structural dip and baffling lithologies within the Haradh Reservoir, 2) faulting within the Reservoir interval, 3) the Carboniferous Al Khlata immediately above the Haradh Reservoir and 4) the variation of Haradh Sandstone Facies and how these may impact fluid flow.
The models have been calibrated against historical data so as to ascertain if a given geological realization is a reasonable subsurface representation to reproduce the actual field production and pressure data. The results indicate that an individual scenario does not provide by itself an absolute explanation to the field observations to date. Instead, a combination of scenarios (fluvial facies and faulting) is considered to be a more feasible option to understand the field observations.