Objectives/Scope: Understanding that capillary forces will act to limit petroleum fluid saturations in water-wet fine-grained rocks, including organic rich source rocks, dates back at least to Hubbert (1953). Likewise, Philippi (1965) noted relationships identifying sorption in/on organic matter as a significant storage mechanism in organic-rich rocks. Contrast these early insights with current unconventional reservoir evaluation, where we observe a disconnect between in situ (core exhumed to surface) measured total water saturations vs. the produced cumulative water volumes from a given stimulated rock volume. Water-free production in gas shales, from gas-wet organic matrix pores, created an early impression that unconventional plays don't produce water. So, in more liquid-rich plays, water cuts were initially under-appreciated: e.g. >80% in the Wolfcamp (stock-tank basis). If measured Sw is so low (core-based calibration), where is the water coming from; or is there an alternative method to more accurately relate in situ to produced water and petroleum production?
Methods/Procedures/Process: Adapting organic sorption models from the 80's, we can split total hydrocarbon volatiles into sorbed and, by difference, non-sorbed (fluid phase) yields. Converting to volumes and adding back dissolved gas using a formation volume factor (FVF) we can estimate the bulk volume fluid phase. This new approach then yields observations regarding remaining water-filled pore volume versus sorbed and non-sorbed hydrocarbon volume explaining the high water cuts in the Permian Basin stratigraphy; and additionally may indicate sweet spots in pore systems in different parts of the rock compared to alternatively derived saturations.
Results/Observations/Conclusions: The final piece of the puzzle comes from basin modeling of petroleum charging in the 90's. Some scientists applied conventional reservoir relative permeability to fine-grained rocks, but new research predicted that progressively finer grained rocks with higher irreducible water should be able to flow oil at progressively higher Sw: at 100nD, both oil and water should flow at Sw > 80%. Lower petroleum phase saturations and adjusted relative permeability curves may better explain observed production behaviors and profoundly alter our view of recovery factor and stimulated rock volume.
Applications/Significance/Novelty: The method offers an alternate and independent method to Dean-Stark-based core / SWC saturation analysis and its pitfalls. Saturation patterns after removal of immobile sorbed oil are different to those derived using the Dean-Stark based method, implying sweet spots / landing zones can be further optimized even in maturing shale plays. Lower oil-in-place – representing only the potentially mobile fluid phase petroleum – means that fracture stimulation has a higher recovery factor than previously thought, with profound effects on the infill volumes / opportunities for future field developments and therefore ultimately for US – and global – oil supply projections.
Interdisciplinary Components: Cross-over technology from organic geochemistry to petrophysics to reservoir engineering.
The Jurassic age Hanifa and Tuwaiq Mountain Formations are regionally established source rocks that charged majority of the oil fields in the region. These formations are comprised of dark carbonate mudrocks with high organic richness and dominantly calcite mineralogy. Several studies were conducted regionally to evaluate the potential of these Jurassic intervals as an unconventional play.
In April 2018, The Kingdom of Bahrain announced the discovery of a major unconventional resource in Khalij Al Bahrain basin following the production of light oil from Tuwaiq Mountain Formation. These results confirmed the viability of the Jurassic source intervals as an Unconventional asset. However, the nature and the location of the resource present a number of operational challenges in a region where development of unconventional resources is at its infancy. This instigates the need to address and tackle these challenges through innovative approaches to enable the effective appraisal and subsequently development of the asset.
This publication introduces the emerging unconventional play in Khalij Al Bahrain basin and discusses the adopted strategies to appraise and develop the asset. The areas for optimization considered include well design, drilling and completion, facilities and shallow offshore/onshore logistics.
The Hanifa and Tuwaiq Mountain formations are Jurassic in age (Figure 1) and consist of a mixed section of dark organic rich limestone beds. These formations are regionally established as the principle source rock that charged majority of the overlying Jurassic reservoirs in the region, and in Bahrain, the cretaceous reservoirs as well. These source rocks are the main targets of the recently discovered Khalij Al Bahrain (KAB) basin in Bahrain with initial resource estimates indicating potentially up to 80 billion barrels of unconventional oil and 14 trillion cubic feet of gas in place.
Location and Geological Settings
KAB basin is located in the eastern part of the Arabian basin straddling the area towards the east of Saudi Arabia, west of Qatar Arch and south of the Zagros fold belts. Majority of the basin today falls within the land bound shallow waters around the main island of Bahrain. Major fields in the area include Awali, Dukhan and Abu Safah which are likely to have been sourced from these Jurassic source rocks (Figure 2). KAB basin also lies in close proximity to the Jafurah basin which is a significant Jurassic unconventional play in Saudi Arabia targeting the same formations .
Bahrain has begun exploring unconventional resources in the Khalij Al-Bahrain Basin for the Tuwaiq Mountain Formation. This work is a case study presenting the workflow for characterizing and modeling the unconventional development in Bahrain all the way from petrophysics through geology, completion modeling, and dynamic simulation.
The work scope consisted of petrophysical modeling 10 key wells including calibration to core data. The petrophysics showed that the lower Tuwaiq Mountain interval with its TOC signature is remarkably consistent across all of Bahrain. The wells modeled in a 3D geological model with reservoir properties distributed throughout the reservoir to confirm resource in-place estimates published in early 2018. Well stimulation treatment on Well 1 was modeled and tied to the production test. A dynamic model was subsequently built to history match the production test. While not unique in its production match, this calibration is an important step for future optimizations in lieu of microseismic data. All of this information was used to form the basis for optimal completions to refine the next appraisal wells with forecasted production rates.
The Tuwaiq Mountain reservoir has commercial potential in Bahrain, particularly in the western area where producibility has been proven. Producibility in the East has not been established as no production tests are available. In addition, future appraisal well locations were identified using the 3D geological model. The best trajectory was chosen such that the wells are estimated to yield EURs more than 500,000 bbls.
The results of this project are important for Bahrain as it highlights the unconventional resource and production potential in the country. For the industry, unconventional development is in its early stages outside of North America and Bahrain’s case study can be utilized to expedite the learning curve in many other basins.
Rueda, Jose (Saudi Aramco) | Valbuena, Jose (Saudi Aramco) | Baki, Sohrat (Saudi Aramco) | Mechkak, Karim (Saudi Aramco) | Mohannad, Mahfouz (Saudi Aramco) | Momin, Ali (Saudi Aramco) | Mulhim, Nayef (Saudi Aramco)
There is little understanding on how the fracture networks in unconventional source plays, commonly referred as Stimulated Reservoir Volumes (SRV), grow with distance and time during the fracturing jobs and connect other offset laterals with or without hydraulically created SRVs. Understanding of this connectivity with offset wells helps on defining the distance among the laterals to avoid any potential negative impact during fracturing and production.
In Jafurah field, several pads have been used to monitor pressures during the fracturing jobs (crosslinked, hybrids and slickwater) and flowbacks. This provides a unique way of measuring the fracturing network pressures at different distances for the initial life of the wells, starting from the generation of the fracture system up to pressures responses due to the production of offset wells.
This paper summarizes the layout and technologies used in a series of pads to understand the connectivity among the wells. Bottom-hole and surface pressures were collected during frac and production in the pads. Also, the outer wells on the pads were monitored from offset contiguous pads. Once the pressure data was synchronized in the different events during fracturing, pressures are plotted to determine the level of pressure disturbance with time. Simultaneously, the absolute values are compared with the minimum stresses, re-opening pressures of natural fractures, and the vertical stresses from the area to determine if the fracture network is reaching the monitor wells and stimulating them. Pressures and derivative behavior are also plotted during the production of the offset wells, to see the level of interference during the initial production, and how the intensity changes as function of time.
It was observed in all the pads that pressures in the monitor wells during the fracturing jobs have four periods: 1) no pressure disturbance is observed (compressibility effects); 2) pressure slowly increases up to equivalent minimum stress (closure pressure); 3) pressure continues increasing from the minimum horizontal stress up to re-opening pressure of the natural fracture systems; and 4) pressure stays above the natural frac re-opening pressure but below the vertical stresses (overburden). It can be seen that pressures in the monitor wells present a cumulative effect, suggesting a generation of fracture systems all hydraulically communicating. This paper will present the different levels of interference observed in the pads as a function of frac types, distance to the monitor wells, and existence of hydraulic fracture in the monitor area. The methodology can investigate interference in unconventional wells during the fracturing treatments and production. This approach will help in understanding how the fracture networks in unconventionals grow and connect to other offset wells.
Techniques for 3D seismic interpretation by geoscientists are continuously undergoing improvements, and future exploration is anticipated to continue to benefit from high-confidence first pass interpretations utilizing all of the available seismic and well data. Workflows have been developed on a'super-merge' 3D volume to produce attribute-enhanced chronostratigraphic stratal surfaces, allowing interpretation of regional-scale seismic facies and associated seismic geomorphology and tectonostratigraphy. In this example, a semi-supervised machine-based learning workflow has provided rapid turnaround interpretation of the structural framework and chronostratigraphy throughout the entire 3D seismic volume, maximizing the value of the seismic information. This workflow consists of a three-step auto-tracking workflow to build a Relative Geological Time (RGT) geo-model directly from the seismic volume. This enables more time to spend on geological validation and interpretation of the stratal surface seismic geomorphology. Study results have provided the foundation for rapid turnaround well and seismic integrated play fairway maps; a powerful tool for stimulating exploration in mature areas or wildcat acreage assessment. This study focused on Middle and Upper Jurassic carbonates deposited on a broad low angle platform on the Arabian Plate. Interpreting in map view on RGT constrained stratal surfaces with attributes such as, relative acoustic impedance and spectral decomposition, is invaluable for visualization since the stratal surface follows the morphology of the imaged geologic features. The ability to select any stratal surface within the volume and flatten, either on a seismic display or the Relative Geological Time geo-model, is particularly useful to establish the timing of major tectonic episodes and accommodation space fluctuations.
Hydraulic fracturing has been widely used for unconventional reservoirs, including organic-rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source-rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate-source-rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source-rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy-dispersive spectroscopy (EDS), were used to investigate the source-rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing-fluid treatments.
The SEM and EDS results before and after fracturing-fluid treatments on the source-rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of the aperture for pre-existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater-fluid-treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core-plug samples. This effect on absolute-gas-permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidence at different scales that aqueous-based fracturing fluid might potentially have a positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater-and seawater-based fluids in stimulating gas production from organic-rich carbonate formations.
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. Ali Almomen, an unconventional gas production engineer at Saudi Aramco, said the company has completed the exploration and appraisal phases of its derisking strategy and is in the middle of various pilot stages.
The Jurassic mud rocks of Jafurah Basin are one of the most promising shale gas reservoirs in Saudi Arabia, retaining considerably high total organic content (TOC) values, and being the source rock for the world-class oil fields of the Kingdom. The purpose of this study is to build a calibrated model with core data using an integrated formation evaluation approach. The model then is frequently used to estimate reservoir properties, minimize uncertainty, and influence decisions on better well placements.
The Tuwaiq Mountain shale play is mainly composed of mudstone with few fraction of dispersed detrital minerals. The Tuwaiq Mountain Formation is divided into two parts: Upper and Lower, where the Lower Tuwaiq Mountain contains higher organic matter and so better reservoir quality as compared to the Upper Tuwaiq Mountain.
The formation evaluation of unconventional shale gas reservoirs presents numerous challenges. The conventional porosity logs, density neutron, and sonic, are heavily affected by the presence of organic matter. The estimation of initial hydrocarbon in place requires accurate estimation of formation water saturation. The conventional equations used to estimate the formation water saturation are subject to a high degree of uncertainty, mainly related to a complex wettability system and unknown formation water resistivity. Therefore, these challenges require the use of advanced and calibrated well logs. The advanced well log technologies used in this study are pulsed neutron elemental spectroscopy and nuclear magnetic resonance (NMR). The analysis can only be achieved through comparison and calibration with micro and nanoscale core data to help building an accurate petrophysical model. The use of the pulsed neutron elemental spectroscopy tool allows the estimation of rock composition, the evaluation of the amount of total carbon present in the system, and consequently, the amount of organic matter in the formation.
Natural magnetic resonance tools are lithology independent and provide an accurate estimation of total porosity. In unconventional shale gas intervals, the T2 distribution is mainly controlled by the surface relaxation factor, and so can be directly linked to the pore size distribution. By applying an appropriate cutoff, based on SEM results, continuous estimation of organic and inorganic porosity can be directly derived from NMR T2 distribution. A saturation model can also be built from a function, linking formation water saturation and organic carbon porosity. The core analysis data are used to understand the pore structure and calibrate the well logs.
The study has proven that the NMR technology works effectively in determining the total porosity, pore system distribution, and estimates of formation water saturation. The nanoscale core analysis is then used to understand the pore structure and to calibrate the well logs.
Bartko, K. M. (Saudi Aramco) | Arnaout, I. H (Saudi Aramco) | Asiri, K. S. (Saudi Aramco) | McClelland, K. M. (Saudi Aramco) | Mulhim, N. I. (Saudi Aramco) | Tineo, R. (Schlumberger Saudi Arabia) | Gurmen, M. N. (Schlumberger Saudi Arabia) | Al-Jalal, Z. (Schlumberger Saudi Arabia) | Pantsurkin, D. (NTC Schlumberger) | Emelyanov, D. Y. (NTC Schlumberger)
Sand in Saudi Arabia is easily accessible through surface mining or excavating large dunes that are API approved, but like many sands around the world, lacks the necessary strength for fracturing high stress formations. To exploit the sand, a novel engineered workflow, enabled by the flow channel fracturing technique was established for qualifying and implementing Saudi Arabian sand to fracture stimulate the tectonically complex ultra-tight "T" carbonate formation.
Channel fracturing does not depend on the proppant pack to provide conductivity, rather on the creation of stable, open flow channels. Therefore, carefully selected sand that can keep the channel structure open under stress can be a viable material to replace up to 80% of the ceramic proppant materials. The local sand used was qualified through unique lab testing procedures to understand the pack behavior under stress, the pillar erosion under stress, and the effects of stress on long-term conductivity. Once qualified, a design methodology was applied to optimize the fracture geometry and pillar placement for the initial field test in Well-A, a horizontal lateral where high strength proppant (HSP) is traditionally used.
A total of six channel fracturing stages with local sand — 40% of the total stages — were placed as per design in two sections of the 15-stage lateral along with four conventional and five channel fracture stages using HSP. A multi-month cleanup and well test period resulted in Well-A being one of the best producing wells in the basin — 26% higher initial production than the next best well. A production log showed sand stages to be producing an average of 15% higher total production than HSP stages. An oil tracer analysis revealed sand stages produced an average of 62% more condensate than HSP stages. This initial production response confirms at least par production with no detrimental effects for channel fracturing with local sand compared to techniques using HSP, with the potential for improved production.
This qualified and field tested completion methodology allows for the potential replacement of a significant portion of imported ceramic proppant with locally sourced sand, an abundant and accessible resource inside the Kingdom of Saudi Arabia and beyond. The benefits of this technology include cost reduction, placement improvement, at least par production and the maximizing of in-country content and value.