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 .
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.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Khan, Riaz (ADNOC Onshore) | Salib, Mina Sameh (ADNOC Onshore) | Ba Hussain, Ali (ADNOC Onshore) | Bin Abd Rashid, Atiqurrahman (ADNOC Onshore) | Aydinoglu, Gokhan (ADNOC Onshore) | Farooq, Umer (ADNOC Onshore)
In this study field, the objective was to identify the causes of low resistivity pay that was limited towards the southwest of the field. Restricting the focus only on diagenesis has not yielded conclusive explanations to delineate the affected area. Alternatively, investigating the influence of structural evolution (folding and tilting) on hydrocarbon charging mechanism and diagenesis has significantly contributed to a reasonable explanation. This, in turn, can potentially impact decisions related to reservoir characterization and field development planning.
The field has adequate coverage of data from vertical (appraisal and observers) and horizontal wells (producers and injectors). The approach of structural flattening at different time intervals was applied in understanding the structural evolution of the field as part of regional tectonic history of the area. The delineation of areas in different paleo-positions has helped in grouping Wells into categories for thorough investigation. Detailed analyses of conventional and advanced logs, and core data were performed which included: petrographic analysis, pore throat and bound water evaluation, and assessment of resistivity log signatures in reference to the paleo-positions of the Wells.
The structural evolution and corresponding hydrocarbon charging mechanisms (drainage and imbibition) have influenced the reservoir hydrocarbon saturation in the field from northeast to southwest. The northeast tilting was triggered by Zagros loading, combined with thermal uplift associated with Red Sea opening. This resulted in imbibition in the extreme northeast and second phase of primary drainage in the extreme southwest of the field. As a result, the area that was previously in water leg during early Tertiary provided more exposure to diagenetic processes which enhanced the total porosity (up to 5p.u.) with high bound water and low resistivity pay. The areal coverage within water leg has been well defined in this study by evaluating the positions of paleo structural closures and hydrocarbon charging mechanisms. This would be useful in capturing diagenetic overprint in properties modeling as well as defining appropriate rock types for better saturation height function and volumetric estimations in this area. Consequently, the field development strategy was to develop the central area, in the first phase, since it was less affected by fluids saturation variations caused by the structural evolution. The study has provided improvement in reservoir characterization techniques for well placement and enhanced field development planning.
The methodology and approach used in this study are usually applied, to some extent, during exploration stages or basin modeling at regional scale with limited data availability and it is not utilized enough for Well placement and reserves estimations in the development stage. The approach applied here, with substantial data availability and integration, can potentially help in making decisions in the early development stage, allow successful field commissioning, and achieve initial production performance and target plateau.
Duaij, Ahmed (Saudi Aramco) | Al-Buali, M. H. (Saudi Aramco) | Ahmed, Danish (Schlumberger) | Arifin, Mohammad (Schlumberger) | Sa, Rodrigo (Schlumberger) | Dehingia, Madhurjya (Schlumberger) | Santali, M. (Schlumberger) | Pochetnyy, V. (Schlumberger)
This paper describes the evolution of descaling interventions via coiled tubing (CT) performed in Saudi Arabia gas wells in the Ghawar field. Throughout these operations, the introduction of new technologies and improved surface equipment has significantly enhanced the efficiency and effectiveness.
CT is the preferred choice for descaling interventions in wells whose reservoirs are underpressured/ depleted because it can accurately place fluid and deploy mechanical tools at the specific depths where scales are present. High leakoff into the formation and hydrogen sulfide (H2S) released at the surface are two main challenges that occur in this well type. Therefore, it is paramount to continuously monitor and control both downhole and surface parameters. The aforementioned challenges can be addressed by optimizing real-time fluid placement or by manipulating the choke size, among other parameters. A chemical plug can be pumped to isolate the reservoir before commencing descaling interventions, but this process may require stimulation or re-perforation of the reservoir system after the treatment. Therefore, it is preferable to use a system that is flexible enough to execute a wide range of operations, from reservoir isolation to descaling treatment, while maintaining the well in balanced or marginally overbalanced conditions.
Previously, CT descaling operations were executed relying only on surface parameters. Today, new technologies are available that can provide live downhole parameters such as pressure, temperature, load, and torque, and these technologies have advanced descaling interventions. Although downhole parameters via downhole tools have been available for years, tools providing such parameters were limited with respect to pumping rate, working pressures, temperature, and ability to sustain high torque and vibration. To address these issues, a new tool was developed that can acquire downhole parameters during milling and clean out operations. The ability to monitor downhole parameters enables field personnel to act instantly to any change in downhole conditions. At the same time, introduction of advanced surface equipment has helped in better handling of returns from the well and in maintaining a constant wellhead pressure irrespective of dynamic returns. Therfore, the treatment is executed within its defined limits and risks of service quality events are mitigated.
This paper describes the evolution of CT descaling intervention treatments and the technologies used. It details how the introduction and integration of new technologies have enhanced descaling operations in Saudi Arabia where real-time decisions were made to optimize treatment, make the operation safer, and prevent formation damage.
Exploration and production of horizontal unconventional tight reservoirs is a growing market in the Middle East. Drilling challenges require precise horizontal steering control relative to the severe formation tendency to achieve higher degrees of accuracy in borehole placement while improving the overall rate of penetration (ROP). This paper discusses the interaction between the polycrystalline diamond compact (PDC) bit cutting structure and rotary steerable systems (RSSs) with respect to vibration alleviation.
Steering using a RSS requires a special bit design to enhance the dogleg capability and ensure minimum vibration levels. A new PDC bit was designed using innovative multilevel force balancing technology—a new theory on PDC cutters layout in force-balanced groups. A group of three or four single-set cutters on a bit profile form a force-balanced cutter group; by carefully selecting the order of layout cutter groups, a new feature of the PDC bit is obtained, ensuring the efficient removal of any ring of rock in a balanced environment.
The new PDC bit design and the implementation of the integrated engineering softwares used to analyze offset wells vibration data, drilling parameters, bit walk tendency, and rock mechanics had a significant effect on the run performance. The clear reduction in the vibration levels enabled more parameters to be applied; thus, helping overcome the formation tendency of the tight reservoir and finishing the run with a good ROP. The even distribution of the cutting forces as a result of the multilevel force balancing of the bit cutting structure reduced the imbalance forces induced as the bit entered transit formation. This increased the overall bit stability, reduced vibration levels, and increased drilling efficiency.
Rao, Jonna Dayakar ((Kuwait Oil Company)) | Al-Ashwak, Samar ((Kuwait Oil Company)) | Al-Anzi, Abdullah Motar ((Kuwait Oil Company)) | Maki, Musaed Yaseen ((Kuwait Oil Company)) | Narhari, Srinivasa Rao ((Kuwait Oil Company)) | Dashti, Qasem ((Kuwait Oil Company)) | Chakravorty, Sandeep ((Schlumberger))
Organic-rich Kerogen of Lower Kimmeridgian to Upper Oxfordian age comprises of thinly laminated Kerogen with calcareous mudstone deposited in deep basinal environment. It has a consistent thickness of 50' in the entire study area with an average porosity of 4-6pu with nanodarcy permeability and is the main source for hydrocarbon plays in Kuwait. This rock sequence occurs at depths of 14000-15000 ft under HPHT conditions. Huge success of shale gas plays in North America has prompted the characterization of these source rocks to evaluate their resource play potential for the first time in Kuwait.
The Kerogen under study differs from proven US Shale gas fields in terms of comparatively higher TOC content, greater depth and much less in thickness (50ft) and in a Pre-salt setting. Hence these are challenging in terms of completion and production. These are inferred to be Type II Oil & Gas prone based on Vitrinite reflectance range from 0.98 to 1.17.
Tight rock analysis (TRA) and geo-mechanical studies of selected core samples within the study area provide critical input for Kerogen characterization. Kerogen is divisible into seven units based on electro-logs and log derived TOC and are correlatable with distinct facies assemblage, TRA derived petrophysical data and Geomechanical properties. Core derived UCS, Triaxial Compression test and Brazilian test based on lab results have brought out clear anisotropic behavior and enabled to bring out mechanical stratigraphy by integrating geomechanical properties and litho-facies variations within the Kerogen. This workflow has brought out the distinction of the carrier beds in alternations with Kerogen-rich layers as well as planned well trajectory along the carrier bed in the central part of Kerogen. Lastly, proppant compatibility tests combined with Young's Modulus provide valuable input for planning horizontal wells and subsequent hydro-frac design for completion.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17765, “First Successful Proppant Fracture for Unconventional Carbonate Source Rock in Saudi Arabia,” by Nayef Ibrahim Al-Mulhim, SPE, Ali Hussein Al-Saihati, SPE, Ahmed M. Hakami, SPE, Moataz Al-Harbi, SPE, and Khalid Saeed Asiri, SPE, Saudi Aramco, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed.
A type of unconventional play currently being evaluated is a carbonate source rock with nanodarcy permeability and very low porosity. This paper will discuss the hydraulic-fracturing- stimulation design, execution, and evaluation for the first successful proppant-fracturing treatment in an unconventional carbonate source rock in Saudi Arabia. The successful two-stage treatment proved that proppant-fracturing techniques could be used to stimulate carbonate formations after modifying the stimulation design (specifically, the perforation strategy, fracturing fluids, and proppant type).
The operator has embarked on an exploration-and-appraisal project to assess unconventional-resource potential in three geographic areas: northwest, South Ghawar, and East Ghawar. Hydraulic-fracturing techniques will be used to enhance production by connecting natural fissures and creating high-connectivity pathways through which gas can flow into the well. The initial focus is in the northwest and in the area of Ghawar. Initial knowledge building from similar plays in North America is being supplemented with internal technical studies and research programs to help solve geological and engineering challenges unique to Saudi Arabia and to locate specific wells planned for 2014.
Acid vs. Proppant Fracturing
The operator has used mainly acid fracturing and matrix acidizing to increase production rates from carbonate formations in conventional gas fields, while proppant fracturing was used predominantly in sandstone formations. This methodology, coupled with the fact that all previous attempts to stimulate carbonate formations in Saudi Arabia resulted in premature screenouts after only 10% of the proppant had been placed in the formation, clearly demonstrates the significance of the first successful proppant-fracturing treatment in an unconventional carbonate source rock in Saudi Arabia.
Jafurah Basin Source Rocks
The Jurassic sediments being targeted in the Jafurah basin as unconventional reservoirs are carbonate source rocks within the Tuwaiq Mountain, Hanifa, and locally basal Jubaila formations (please see the complete paper for a detailed geological description). The H-1 well is the first well drilled on a seismic anomaly, and it encountered a thick organicrich Jurassic source rock. The thick sequence of source rock in the H-1 well, as well as other areas within the basin, may suggest the possibility of a commercially viable unconventional play. As a followup to the drilling of the H-1 well, a geophysical forward-modeling project was initiated to investigate the cause of the seismic-amplitude anomaly in the Jafurah basin. The study revealed that the formation encountered in the H-1 well has an overall lower acoustic impedance, which appears to be the result of its high total organic content.
Drilling and Coring
The H-2 well, east of the giant Ghawar field, was drilled to evaluate several Jurassic source-rock targets. The well was completed with 4½-in. tubing, a 7-in. liner with a 7-in. permanent packer, and a 25-ft sealbore receptacle. The tubing and annulus were displaced with 65-lbm/ft3 brine. The well was designed to be re-entered for horizontal sidetracking.
Five cores were cut for laboratory testing and analysis. Acid-solubility tests were performed on the core-plug samples to determine their solubility in hydrochloric acid (HCl). X-ray-diffraction analysis was performed on four core samples before and after the acid-solubility tests, showing that the four samples analyzed consisted mainly of calcite with smaller fractions of dolomite, quartz, anhydrite, pyrite, and clays.
Deep-penetrating charges were used in Well H-2, in conjunction with underbalanced perforating to minimize perforation damage and ensure clean perforations. In addition, 3,000 gal of 15% HCl was pumped as a preflush before pumping the pad in each stimulation treatment to further aid in removal of debris from the perforation tunnels.
The improvement of the success of the well drilling is an important task during the development of hydrocarbon reservoirs, and the use of three dimension mechanical earth model (MEM) is key to predict the behavior of drilled well and to prevent damaging the well. The MEM encapsulates several information related to pore pressure, mechanical properties of the reservoir rock, the geometry of the reservoir limits and the overburden and the stress regime. Various workflows were proposed to build and update the MEM. However, those approaches do not incorporate the complexity of the carbonate rocks. In fact, the carbonate rocks, hold heterogeneous pore systems that impact the rock strength and the pore pressure behavior. The heterogeneity of the pore systems is due to the specificity of the deposition process of the carbonate rocks, mainly composed of fauna and or flora, and the rate of diagenesis.
In this paper, we propose a workflow that improves the modeling of the mechanical properties for carbonate reservoirs. This workflow starts by reconciling data at different scales, diagenesis rate at thin-section scale, scratch and laboratory strength tests at plug scale, electrical logs at well scale, and three dimension sedimentology and seismic volumes at reservoir scale. The second step is to establish the relationship between the mechanical properties, the pore pressure, the seismic attributes, the sedimentology and the rate of diagenesis. The last step allows interpolating and assessing the uncertainty of the mechanical properties and pore pressure in the three dimension reservoir model.
The workflow was applied to an off-shore carbonate field in South-America. It showed that there is a strong relationship between the type of fauna and flora, composing the carbonate rock, and the rock strength and pore pressure. The three dimension mechanical model, at hundred meter horizontal resolution and one foot vertical resolution, allowed to quantify the risk associated with the drilling of the previously planned wells, to improve the location for future drilling wells and to optimize the drilling parameters such as mud weight.