|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Speaking last week at AAPG’s Global Super Basins Leadership Conference in Houston, he added that since then, there have been a series of large discoveries on both the US and Mexican ends of the prolific basin, a prime example of how an incredibly rich play must be periodically rejuvenated by new technology and new thinking. Even Saudi Aramco, with its laser focus on maximizing production in the Kingdom of Saudi Arabia, is still working on understanding its inventory, which is rich but complicated. He said only 20% of the oil and gas volumes had been discovered in the Kingdom. While the Middle East has more oil to find than any other country, based on basins he described, the level of difficulty is rising. While Saudi Arabia has some of the best rock in the world that “does not mean it does not have challenging reservoirs that are part of our portfolio today for upside potential.”
Katsevich, Alexander (iTomography Corporation and University of Central Florida) | Frenkel, Michael (iTomography Corporation) | Sun, Qiushi (Aramco Services Company: Aramco Research Center - Houston) | Eichmann, Shannon L. (Aramco Services Company: Aramco Research Center - Houston) | Prieto, Victor (iTomography Corporation)
Microcomputed tomography (microCT) of cores yields valuable information about rock and fluid properties at pore scale for conventional rock and at rock heterogeneity scale for unconventionals. High levels of uncorrected X-ray scatter in computed tomography (CT) data lead to strong image artifacts and erroneous Hounsfield unit (HU) values, making reconstructed images unsuitable for accurate digital rock (DR) characterization (e.g., segmentation, material decomposition, and others). MicroCT scanners do not include scatter correction techniques. To fill this gap, we developed a new methodology to measure and remove the scatter component from raw projection microCT data collected during rock core scans, and ultimately improving the image quality of scanned cores.
Widely used approaches for scatter estimation, based on Monte Carlo (MC) simulations and simplified analytical models, are time-consuming and may lose accuracy when imaging complex unconventional shale cores. In this paper, we propose a more practical approach to perform scatter correction from direct scatter measurements, an approach that is based on the beam-stop array (BSA) method. The BSA method works as follows: The radiation scattered by the core sample is emitted in random directions. By placing an array of small, highly absorbing beads between the source and the core, the primary X-ray signal through the beads is blocked, but the overall object scatter signal is not affected. The observed values in the beads' shadows on the detector are assumed to be scatter signal. Performing interpolation of the scatter signal between the shadowed by beads pixels on the detector gives an estimate of the scatter signal at every pixel on the detector. Subtracting scatter from projection data yields scatter-corrected data used for 3D CT core image reconstruction.
To develop the core scatter correction methodology, we executed the following three tasks: (1) performed modeling of primary and scattered signals to optimize the BSA design (beads size and layout) and scan parameters; (2) developed and implemented an accurate scatter correction algorithm into our 3D microCT image reconstruction workflow; and (3) tested the proposed methodology using four shale core samples from the United States and the Middle East.
To better assess the impact of scatter, all experiments with shale core plugs presented in this paper were conducted using source energy of 160 kVp. Our results demonstrated that in many cases, especially with higher attenuating cores, failing to correct for X-ray scatter may result in significant loss of image reconstruction accuracy. We also showed that the developed methodology allows for accurate estimation and removal of scatter from the raw (projection) CT data, enabling reconstruction of high-quality core images that are required for performing DR analysis.
To assess the impact of X-ray scatter on the accuracy of DR segmentation, we compared the amount of resolved air-filled space using a stack of image slices by thresholding for the air regions. Our results showed that the amount of detected air-filled space may increase significantly when scatter correction is applied.
The presented scatter correction methodology is general and can be used with any microCT scanner used by the petroleum industry to improve image quality and derive accurate HU values. This is of significant importance for quantitative characterization of highly heterogeneous rock with fine structural changes, as is the case for shale. Ultimately, this methodology should expand the operational envelope and value of microCT imaging in the exploration and production workflows.
The unconventional revolution in North America has firmly established unconventional resource plays as an integral component of global hydrocarbon production. The established North American resource plays are heterogeneous and vary considerably in terms of play type, stratigraphic organization, and the lithology of the target unit. The Middle East has several world-class source rocks that have charged giant and supergiant conventional fields, which implies many opportunities to develop unconventional resource plays. Within this study, the stratigraphic organization of two prolific source rock intervals within the Early Silurian (Qusaiba Member) and Middle-Late Jurassic (Tuwaiq Mountain Formation and equivalents) is characterized from public-domain data sets. From this, a variety of unconventional plays are conceptualized within these resource intervals.
The systematic classification of established resource plays in North America facilitates analogue identification for these emerging resource intervals across the Middle East. The Montney play is identified as an analogue for the Silurian resource interval and can be used to help validate unproven unconventional play concepts. Within the Jurassic resource interval, multiple analogues are identified that characterize different aspects of the emerging unconventional play types. For instance, stratigraphic architecture within the emerging Tuwaiq Mountain shale play is comparable to the Vaca Muerta play of the Neuquén Basin in South America, while mineralogy is similar to that within the Eagle Ford play and porosity development is akin to the Marcellus play. Applying understanding from these analogues can enable more informed and efficient exploration, appraisal, and development decisions within these frontier and emerging Middle East resource plays.
Kurdi, Mohammed (Saudi Aramco) | Sadykov, Almaz (Saudi Aramco) | Momin, Ali (Saudi Aramco) | Rueda, Jose (Saudi Aramco) | Kazakoff, Sergei (Saudi Aramco) | Baki, Sohrat (Saudi Aramco) | Mechkak, Karim (Saudi Aramco) | Kalbani, Abdullah (Saudi Aramco)
The objective of this paper is to showcase the work done to improve proppant placement using high viscous friction reducers in Saudi unconventional reservoirs. Clean-based fluids, mainly water with friction reducer additives, do not exhibit enough viscosity to place the desired proppant volume. Nevertheless, the respective production results made clean-based fluids outperform heavy-based fluids (guar gum-based fluids with cross-link additives).
As the friction reducer is the main chemical to be pumped with water forming the clean-based fluid, as known as slickwater, its optimization is vital in placing the desired proppant volume by using minimal water volume. The optimization comes from two results: friction reducer type and concentration. To determine the best suited type of friction reducer to increase the viscosity of the fracture fluid and reduce drag/friction, lab experiments have been conducted using the available friction reducer types in the industry. Water samples from the field have been collected and was then tested to determine the water quality. Different additives were added and their viscosities were measured using rheometers at surface and downhole temperatures. High-Viscous Friction Reducers (HVFRs) generated the best viscosity at both surface and downhole conditions, when compared to other friction reducers in the market. To determine the optimum concentration of HVFR, different concentrations were used in the high temperature rheometers at surface and bottomhole conditions. The results show exponential relationship between the concentration and the viscosity of HVFR.
The second phase of the project is measuring the resultant conductivity of the HVFR. A lab experiment was conducted using a conductivity cell to measure the conductivity of a proppant pack. A sensitivity analysis was conducted, changing the fluid type inside the proppant pack. Slickwater with HVFR showed better performance than linear gel and crosslink fluids, and showed similar performance to other friction reducers from a conductivity point of view. The third phase of the project is the field test. A well was selected for the trial test where the well lateral was landed in a very challenging zone for proppant placement. The well's average proppant placement percentage was 62%, significantly hindering its expected production results. With the advent of HVFR, the proppant percentage improved significantly to 98%.
The paper highlights the importance of HVFRs in improving proppant placement in challenging unconventional reservoirs, to improve well productivity. This work summarizes the lab tests conducted to ensure placement would be achieved when used in the field, without jeopardizing the production results due to the enhanced viscosity/reduced friction. This work provides a breakthrough in slickwater placements in unconventional reservoirs, as this fracture fluid has become commonplace in Saudi unconventional reservoirs, and in many other unconventional reservoirs around the globe.
Gaining an understanding of the well to well interference during hydraulic fracturing and subsequently production interference is paramount in optimizing the costs associated with field development. Much work has been done in the industry to better understand the interference during hydraulic fracturing and production among adjacent wells. This paper presents an analysis that employed both a pressure interference analysis and chemical tracer analysis to gain a better understanding of the fracture interference in a well pad in the Jafurah field. The subject pad consists of 4 wells. Two of which run parallel in a north direction and the other two run parallel in the southern direction. All four wells were hydraulically fractured with slickwater design. Adjacent to the subject pad is another pad that had been previously stimulated with crosslink design and was used for pressure monitoring. The distance between the laterals was relatively similar (X ft) with one exception (2 × ft).
Initially, one well from both directions was stimulated with 33 stages each of slickwater design and the plugs were subsequently milled out. Afterwards, the other two wells were stimulated with 33 stages of slickwater each. In 7 of the 33 stages of the later wells, 20 oil and 20 water tracers were injected in sequence in an attempt to study the physical extent of the fractures generated. While the latter two wells were being stimulated, the wellhead pressure on the parallel wells was being monitored and recorded along with the wellhead pressures on the adjacent pad.
During flowback, the southern wells were flowed back simultaneously and flowback samples were collected to be analyzed for tracers. Subsequently, the northern wells were opened up to flowback in the same manner and flowback samples were also collected for tracer analysis. Wellhead pressure was monitored on the adjacent pad during flowback of all the wells.
The pressure data during the fracturing operation indicated for distance × ft and the size of stimulation stages pumped, a level of communication which was further verified by the production interference analysis as well as the tracer data.
Shale gas characteristics and operation are different than conventional gas. A shale gas plant is typically smaller in capacity ranging from as low as 15 MMSCFD to the typical 200 MMSCFD cryogenic train size. The main challenges are the unpredictable gas compositions and flow rates during the development stage, which makes liquid recovery difficult. These uncertainties are challenges for a traditional cryogenic plant which is designed for a specific range of feed gas flow and compositions.
Shale gas compositions are richer in hydrocarbon liquids with ethane plus content ranging from 6 to 10+ GPM. Ethane is a valuable feedstock for petrochemical production, but ethane prices are unattractive in today’s environment. Most gas plants are operating in ethane rejection, resulting in a loss of propane revenue. To maintain propane recovery during ethane rejection, the refrigerated reflux category of NGL recovery technologies (e.g. Fluor’s Deep Dewpointing Process, DDP) has been developed to fully reject ethane while recovering 95% plus propane. The typical refrigerated reflux process is a refrigerated, non-expander process that can be turned down to as low as 4:1. The process can be operated in ethane recovery with minimal changes to the process to recover up to 60% ethane. The DDP process can also be enhanced to recover 95% ethane with additional compression. This technology has been proven in successfully operation in several installations.
Presently, Fluor and Joule Processing are leveraging the versatility of the refrigerated reflux process by productizing the proven and patented DDPSM version of this technology in the form of an "equipment kit". These equipment kits will offer a relatively small modular footprint to reduce installed cost and accelerated factory lead-time to shorten the overall EPC schedule.
This paper discusses the design, costs and economics of the DDP process for a typical shale gas plant, and the methodology to switch from propane recovery to 60% ethane recovery during normal operation, and to high ethane recovery with the bolt-on design. Key design challenges from an operating DDP unit are also detailed.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Belhaij, Azmi (Saudi Metal Coating Company) | Alkamil, Ethar H. K. (University of Basrah)
Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.
Since 1st February 2019 Total E&P UAE Unconventional Gas B.V started to operate the Diyab shale gas field in which three horizontal exploration wells had been drilled by ADNOC. Mult-stage hydraulic fracturing treatments were performed on these wells followed by long term well testing to assess the formation potential for a further development. It was a challenging project since it was the first shale gas frac campaign in UAE where the unconventional reservoir developments are at beginning phase. Various operational problems emerged in wireline pump down, coiled tubing milling and H2S treatment operations, especially during execution in the first well. These operational issues were mainly related to equipment availability and compatibility, personnel competency, logistics support and societal concerns of environment. Corrective measures and innovative designs were conducted to solve the technical issues and improve the operation performance. Good learning curves of different operations were achieved from the first well to the third one. The lessons learned from this hydraulic fracturing campaign are valuable experience that will be applied to the future pilot wells in Diyab field for the continuous optimization.
Newby, Warren (Total SA) | Abbassi, Soumaya (Total SA) | Fialips, Claire (Total SA) | D.M. Gauthier, Bertrand (Total SA) | Padin, Anton (Total SA) | Pourpak, Hamid (Total SA) | Taubert, Samuel (Total SA)
The Upper Jurassic (Oxfordian to Late Kimmeridgian) Diyab Formation has served as the source rock for several world-class oil and gas fields in the Middle East. More recently it has become an emerging unconventional exploration target in United Arab Emirates (UAE), Saudi Arabia, Bahrain and its ageequivalent Najhma shale member in Kuwait. The Diyab is unique in comparison to other shale plays due to its significant carbonate mineralogy, low porosities, and high pore pressures. Average measured porosities in the Diyab are generally low and the highest porosity intervals are found to be directly linked to organic porosity created by thermal maturation. Despite low overall porosities, the high carbonate and very low clay content defines an extremely brittle target, conducive to hydraulic fracture stimulation. This coupled with a high-pressure gradient facilitates a new unconventional gas exploration target in the Middle East. However, these favorable reservoir conditions come along with some challenges, including complex geomechanical properties, a challenging stress regime and the uncertainty of whether the presence of natural fractures could enhance or hinder production after hydraulic fracture treatment. Only recently has the Diyab been studied in detail in the context of an unconventional reservoir. This paper presents an integrated approach allowing a multidisciplinary characterisation of this emerging unconventional carbonate reservoir in order to gain a better understanding on the plays' productivity controls that will aid in designing and completing future wells, but already encouraging results have been observed to date.
Laboratory analysis was conducted in order to study the effect of a phosphonate scale inhibitor on a mixture of hypersaline Arabian Gulf seawater and formation water under high temperature/high pressure (HT/HP) applications. The objective of this study was to identify the minimum scale inhibitor concentration required at various temperatures to achieve a cost-effective solution in minimizing the formation of common oilfield scales. Development of such a product would aid in the utilization of seawater-based fracturing fluids by controlling the scaling tendencies of the system, especially when exposed to formation waters. Utilizing a scaling software, various types of scales were modeled by testing different seawater/formation water ratios at temperatures ranging from 270 – 330°F. A dynamic scale loop was used which allowed seawater and formation water to be pumped into the system, thereby generating differential pressure data. The exponential increase in pressure would indicate scale formation. Various concentrations of scale inhibitor were then introduced to the mixtures and tested to determine the minimum scale inhibitor required for scale mitigation. Compatibility tests were also conducted to test for the efficacy of the scale inhibitor.
Based on the scaling software, barite was identified as the primary scale generated. Barite scale has a low solubility of 2 mg/L and is one of the most difficult scales to mitigate. The highest concentration of barite scale occurred in a 50/50 ratio mixture of formation water and seawater. For all the temperatures tested, the scale loop was run at the concentration with the most barium sulfate present. The results for this research concluded that at 270°F and 300°F, the minimum scale inhibitor concentration was 2000 ppm and 1500 ppm, respectively. Both treatments successfully mitigated the following types of scales: barium sulfate, calcium sulfate(s), and strontium sulfate. At 330°F, the minimum scale inhibitor concentration was lower. This decreasing trend in scale inhibitor concentration as temperature was increased is attributed to the temperature constraint of phosphonate scale inhibitors. As a result, adding the phosphonate scale inhibitor contributed to the formation of calcium phosphonate complexes that led to the rise in pressure in the scale loop test. This hindered the efficiency of the treatment and portrayed the dramatic effects of temperature and inhibitor concentration on scale mitigation. This research pushes the thermal constraints of a phosphonate scale inhibitor up to 330°F to test its efficiency and overall treatment integrity. There are also fracturing fluid applications introduced utilizing a seawater source with one of the highest total dissolved solids (TDS) concentrations in the world. Barium sulfate and other scales were successfully mitigated at various high-temperature applications for these systems utilizing a phosphate scale inhibitor.