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 .
One of the major challenges, in comparing unconventional well performance during the appraisal phase, is the lack of long-term production data. In unconventional reservoirs, the main factor impacting well production is the generation of long effective fractures and large stimulated reservoir volumes (SRV). Different fracturing techniques are commonly tested during the appraisal phase, to find the best technique to maximize hydrocarbon recovery. Therefore a more robust methodology is required to analyze the production for a limited test period during the initial flow back.
This paper summarizes the application of the Rate Transient Analysis (RTA) to assist the selection of the best fracturing technique, through the estimation of the effective fracture length and a well potential index. The applied technique uses both the hydrocarbon and water production to characterize the initial fracture network performance. The implemented workflow factors in production data collection, flowing bottomhole pressure calculations, definition of fluid type at reservoir conditions and reservoir characteristics, and diagnostic plots generation. First, the methodology starts with calculating and plotting the rate normalized pseudo pressures vs. the square root of time for the total hydrocarbon rate and the equivalent plot for the water. If the wells were producing in a linear flow regime, the resultant slope of the straight line would provide the well potential index, which is a function of the product of the fracture half-length and the square root of the reservoir permeability. A calibrated permeability model from petrophysics was used as an input, to calculate the effective fracture half-length for each of the analyzed wells. These measured parameters allowed for the comparison of different fracturing techniques in a consistent framework.
The analysis was implemented in several wells where different frac techniques had been tested, among these were conventional crosslink, hybrid fracs, and slickwater. This methodology was successful on identifying which frac technique consistently provided the longest equivalent fracture half-lengths and SRV. It was found that the linear flow in the subject unconventional reservoir starts after a few hours of production, and extends up to the maximum produced time on the wells studied, which was 6 months. Results from pad well cases clearly confirmed the most effective stimulation strategy for the development scenario.
The workflow assists the completion optimization process during the appraisal phase for unconventional fields, where short production data is available. The proposed workflow helps production engineers in the decision-making process to select the best technique and perform initial flowback troubleshooting.
Sadykov, Almaz (Saudi Aramco) | Baki, Sohrat (Saudi Aramco) | Mechkak, Karim (Saudi Aramco) | Momin, Ali M (Saudi Aramco) | Rueda, Jose I (Saudi Aramco) | Kazakoff, Sergei (Saudi Aramco) | Kalbani, Abdulla (Saudi Aramco) | Kurdi, Mohammed (Saudi Aramco) | Mulhim, Nayef I (Saudi Aramco)
Saudi Aramco has made substantial progress in developing its unconventional gas resources with Plug and Perf (PnP) completions and multistage slickwater fracturing, with optimal production performance. Wells in Jafurah basin are generally completed with 5,000 feet horizontal lateral and up to 33 stages with 4 to 5 clusters per stage. Increasing the number of clusters per stage in such completions could lead to cost and efficiency optimization, but also increases the risk of having non-stimulated clusters, considering geomechanical heterogeneity, and without providing sufficient pumping rate. Thus introducing diversion techniques becomes a necessity in this unconventional play to optimize cluster efficiency, improve operational efficiency, and thus reduce cost.
Near wellbore chemical particulates and intra-well perforation mechanical diversion techniques from degradable materials found their wide application in different unconventional assets. A mega-diversion experiment with both techniques took place in one of the wells, where a damaged section of the lateral did not allow regular PnP operations at the toe. Laboratory tests before operation ensured degradation of the material is within operational thresholds for positive isolation. The lateral section below the casing deformation (1,200 ft in the toe section) was planned with 30 clusters in one single stage, with the intrawell diversion technique. Another eight stages in 1,200 feet were attempted with a standard five cluster stages as a baseline. The remaining 2,400 feet of the lateral were stimulated with eight stages, 10 clusters per stage, and sequential application of both intrawell mechanical and near wellbore diversion technologies. Other wells in the area, which had damage in the casing, were also completed with mechanical diverters.
The 1,200 ft lateral section was successfully stimulated without additional well intervention operations with a selected diversion technique. Proppant placement challenges were encountered in the regular five cluster stages with significant improvement in the subsequent 10 cluster stages introducing diversion. Positive diversion indication was confirmed by surface pressure observations and mainly proppant placement success. Multiple instances of non-typical pressure behavior were observed during placement of the mega-diversion stages. This pressure behavior is the subject of technical analysis and results will feed into the future design strategy.
The intrawell mechanical diversion technique showed positive diversion indications in different wells in Saudi Arabia, with good repeatability of slickwater propped fracturing treatment success. This technique could be utilized whenever wellbore accessibility challenges are encountered, or during refracturing application cases. Both diversion technques could be used efficiently to stimulate the clusters and optimize well intervention operations, by minimizing the number of stages per well without compromising stimulated reservoir volume.
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.
Hao, Zhang (Baker Hughes, a GE Company) | Nora, Alarcon (Baker Hughes, a GE Company) | Julio, Arro (Baker Hughes, a GE Company) | Guillermo, Crespo (Baker Hughes, a GE Company) | Diego, Licitra (YPF) | Carlos, Hernandez (Chevron LC YPF-CVX JV)
The estimation of fluid properties and rock composition is an integral part of formation evaluation. Unconventional resources such as organic-rich shales are geologically complex, due to great variability in rock composition and post-depositional diagenetic processes. In addition, low porosities, such as those usually encountered in unconventional reservoirs, are not well defined from conventional logs due to the large influence of the rock lithological components and high uncertainties of the log measurements. The errors in estimated porosity not only relate to measurement errors, but also to the incomplete knowledge of matrix parameters. Consequently, a reliable method that integrates mineral and fluid petrophysical models is needed to determine the key formation properties in whole-rock characterization.
It is well known that the most important petrophysical parameter obtained from nuclear magnetic resonance (NMR) logging data is a lithology independent porosity. The ill-defined problem in NMR inversion requires proper regularization methods to stabilize the inversion results. The incorporation of conventional logs as penalty constraints in the NMR inversion process can lead to an improved quantification of fluid typing and formation porosity. However, the accuracy of the fluid model is also influenced by the quality of the estimated matrix properties. Geochemical logs based on pulsed neutron technology have been successfully applied to determine elements for identifying lithology and mineralogy. A probabilistic method incorporating geochemical and conventional log measurements can reliably estimate the matrix mineral composition and porosity. However, a good understanding of the fluid properties is also important for accurate results from the mineral model. The fluid and the mineral model complement each other. Consequently the integration of the two models using NMR, geochemical, and conventional logs can provide an improved whole-rock characterization.
In this work, a unified workflow that includes petrophysical relations and rock physics models is proposed. Probabilistic mineralogy inversion using geochemical and conventional logs solves for matrix properties that are used as inputs for the fluid inversion model. Simultaneous inversion using NMR echo trains and conventional logs determines pore fluid composition and formation porosity that are used as fluid parameters to improve the results in the mineral model. By using both inversion models jointly, a set of petrophysical properties that account for all available log measurements can be determined for the whole rock, and the integrated workflow can potentially reduce the uncertainty in the well log interpretation that usually applies a limited set of logs. A field example from an Argentina well in the Vaca Muerta unconventional play is presented and discussed to show the superior interpretation proficiency of the proposed methodology.