One of the world’s leading energy watchers says the second shale revolution will come in the form of LNG exports. After 70 years of production, more than 30% of the Arab C reservoir stock-tank original oil in place has been recovered through various mechanisms including natural depletion, waterflooding, gas lift implementation, and horizontal-well development. The North field offshore Qatar was observed to have a chance of inner annuli becoming charged with shallow-gas pressure with possible communication to other annuli, which was thought to be a well integrity concern. Airborne imaging spectroscopy has evolved dramatically since the 1980s as a robust remote-sensing technique used to generate 2D maps of surface properties over large areas.
Nonaqueous drilling fluids, such as synthetic-based and oil-based mud (SBM and OBM, respectively), are used frequently to drill one or more sections of a well to reduce drilling problems such as shale sloughing, wellbore stability, and stuck pipe. This paper describes how a technique known as applied-surface-backpressure managed-pressure drilling (ASBP-MPD) can alleviate the limitations of conventional deepwater well control. Three onshore fields in the Emirate of Sharjah, United Arab Emirates, have more than 30 years of production history from more than 50 gas-condensate wells. Since the 1980s, many technical works have focused on improving the ability to detect hydrocarbons inside the riser and safely remove them from the system. This trend gained extra momentum with the advent of systems such as riser-gas handlers and managed-pressure drilling.
Polylactic Acid (PLA) is increasingly used in the oil industry and specifically for diversion in matrix acidizing as evidenced by a number of field cases recently published. The solid polyester is particularly attractive due to its ability to degrade in the presence of water and heat, negating the need for cleanup fluids or complicated procedures. A majority of the analysis on the effectiveness of PLA thus far comprises experiments on artificially created slots, filter cake analysis, and field trials. This paper demonstrates the effect of PLA in wormholes developed by acidizing outcrop cores.
In these experiments, a wormhole is generated in a portion of the core by limiting the amount of acid injected. Next, the PLA is injected into the core using a heavy brine suspension. Finally, more acid is injected until a wormhole breaks through the core. Computer Tomography (CT) scans are taken, and the pressure drop across the core is recorded at each stage. Experiments were conducted for a variety of initial wormhole lengths.
It can be difficult to suspend PLA while injecting it through a core in a way that is benign to the core, acid, and PLA; and in a way that does not add any pressure drop or diversion due to viscosity changes. This paper describes and justifies a suitable method of keeping PLA suspended to allow its use in core flood experiments. The CT scans show that even when the PLA plugs the wormhole, additional acid tends to continue to develop the dominant wormhole. The pressure drop profiles show that the pressure drop due to PLA injection is proportional to the mass of PLA, both in the wormhole and on the core surface. The pressure profiles also show that there is an increased pressure drop due to PLA in the wormhole versus in a filter cake on the surface.
This paper details a new method of visualizing and analyzing the effect of PLA in a multistage acidizing treatment. Empirical correlations are presented for estimating the pressure drop caused by PLA, both as a filter cake on the formation surface and as a filling inside wormholes. The correlations were incorporated in a comprehensive carbonate acidizing model to predict the diversion efficiency of PLA particles. The simulation is verified using published field trials of diversion treatments.
In the last decade, there have been several publications describing the use of Polylactic Acid (PLA) as a diverting agent in multistage matrix acidizing treatments. The solid polyester is particularly useful as a diverting agent because it hydrolyzes in the presence of heat and water leaving no residue in the formation, negating the need for any clean-up fluids. Most of the publications thus far focus on characterizing the physical and chemical attributes of the diverter and demonstrating its effectiveness in field trials. This paper develops some general guidelines for the application of PLA diversion in multistage matrix acidizing treatments by conducting sensitivity analysis on the design parameters of three field cases.
To carry out these sensitivity analyses, an empirically derived model that describes how PLA creates a skin factor during multistage matrix acidizing treatments is incorporated in a near wellbore simulator. This simulator also tracks the fluid interfaces, models the transient reservoir and wellbore flow, and calculates the wormhole propagation rate and a number of completion skin factors. The design parameters that will be investigated include whether PLA should be sized to enter the wormhole or to bridge at the sand face, diverter concentration, specific cake resistance, the number of diverter stages, and the total volume of acid pumped. The efficiency of the diversion treatments will be compared based on the overall final skin factor and uniformity of the skin profile along the well.
This paper reveals that PLA is significantly more effective in creating a uniform skin profile if it is designed to bridge the wormhole openings rather than to enter them. It is also shown that increasing the diverter concentration or using a diverter with a higher specific cake resistance can create a more uniform skin profile but there is an inverse relationship with the overall skin factor. It is shown that using the same volume of the diverter in a few diverter stages is better than pumping all of the diverter at once, but that there is a limit where using a larger number of stages does not add any benefit. The study highlights the need to fully stimulate the high permeability zones before pumping the PLA, and finally, it suggests that the total volume of acid used should be higher when PLA diversion is used to offset the adverse effects on the overall skin factor.
Located in the Arabian gulf, the Qatari North Field is the largest non-associated gas field worldwide with estimated reserves exceeding 900 trillion cubic feet of recoverable gas, or approximately 10% of the world's known reserves. Development of this field present tough conditions for all aspects of well drilling and completion activities. Particular challenges for performing well intervention, which have driven operators and manufacturing and service companies to develop innovative strategies and systematic technology collaboration for intervening these fields in a safe and efficient manner.
Recently, two new sub-horizontal wells with multiple reservoir zones needed to be perforated and selectively stimulated. Considering safety factors and operational efficiency, the insertion and retrieval under pressure system was identified as the best alternative to convey an average length of 600ft of 2 7/8-in. guns in single trips with coiled tubing (CT). Although this system has been successfully used in other regions, downhole adverse conditions required specifc components and implementing innovative methods, including the use of 5/16-in. braided slickline for gun deployment, and 2 3/8-in. CT with fiber optic telemetry capability for accurate depth correlation, precise actuation of the firing head system and confirmation of gun detonation.
As result of a dedicated planning and preparation process, the two wells were perforated in controlled conditions and each of the applied technologies proved its value. The use of 5/16-in. braided slickline reduced the gun deployment time by at least 2 days from the planned schedule, and the H2S rated connectors and the pressure-pulse firing head gave the confidence to avoid any issues when the perforating assembly was downhole. In respect to the CT real-time telemetry system, this technology provided an exceptional indication of bottomhole conditions throughtout the operation by enabling precise control of the firing head mechanism, identification of gas/water fluid contact in the well, and monitoring of formation response, which eliminated the need for initially planned nitrogen lift operations.
This paper describes the selection process of the key technologies deployed for performing CT conveyed perforating operations in two sub-horizontal wells in Qatari North Field, and discusses the workflow developed for those interventions. It then presents case studies and lessons learned and provides conclusions from the experiences gained for performing CT conveyed perforating operations in North Field.
Al-Garadi, Karem (King Fahd University of Petroleum and Minerals) | Aldughaither, Abdulaziz (King Fahd University of Petroleum and Minerals) | Ba alawi, Mustafa (King Fahd University of Petroleum and Minerals) | Al-Hashim, Hasan (King Fahd University of Petroleum and Minerals) | Sibaweihi, Najmudeen (King Fahd University of Petroleum and Minerals) | Said, Mohamed (King Fahd University of Petroleum and Minerals)
Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells.
In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity.
The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.
The onshore Bahrain Field is a multi-reservoir oil and gas field in the Kingdom of Bahrain. Hydrocarbons are found in various stratigraphic intervals from Devonian to Upper Cretaceous in mostly carbonate reservoirs. Clastic reservoirs are scarce in the post-Permian section but dominate in the pre-Permian section. The Lower Cretaceous Kharaib Limestone is an oil reservoir. The unit was tested in different exploratory wells in the early life of the Bahrain Field and it was found to be of low permeability but produced oil.
The first phase of field development in Kharaib was initiated in the 1970s and after an initial period of dry oil production, the wells produced for a long time with high water cut (more than 90%). In the early 2000s, a horizontal well drilled in the reservoir provided encouraging results. Main development activities started from 2010 onwards, after Tatweer Petroleum – Bahrain Field Development Company W.L.L. ("Tatweer Petroleum") was formed. Thirty horizontal and fifteen deviated producers (a total of forty-five wells) were drilled during the period 2010–2014 and as a result, oil production from the reservoir increased significantly. However, within a short period of time, most of the wells started producing with high water cut (more than 90%) and image logs recorded in many horizontal wells showed presence of fractures. Based on this observation and 3D seismic analysis, Kharaib was characterized as a fractured reservoir and high water production was attributed to it. Later on, many wells had mechanical failure due to casing corrosion developed against the shallower Shuaiba aquifer. All development activities were subsequently stopped for the reservoir due to economic risk.
In 2016, a renewed effort was undertaken to analyze all past data including; regional tectonics, core data, 1970s build-up studies, cement integrity, and image log interpretations. This back-to-basics analysis indicated that the primary cause of high water production in the Kharaib wells is lack of zonal isolation with Shuaiba (casing corrosion wells excluded) and not due to the presence of occasional fractures.
Development activities restarted in 2017 that focused on addressing the zonal isolation and casing integrity issues. Seven wells have been drilled to date producing with an average water cut of 22%. More development wells are planned in the future thereby giving a new lease on life to the reservoir.
Temizel, Cenk (Aera Energy) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Putra, Dike (Rafflesia Energy) | Asena, Ahmet (Turkish Petroleum Corp.) | Ranjith, Rahul (Far Technologies) | Jongkittinarukorn, Kittiphong (Chulalongkorn University)
Smart field technologies offer outstanding capabilities that increase the efficiency of the oil and gas fields by means of saving time and energy as far as the technologies employed and workforce concerned given that the technology applied is economic for the field of concern. Despite significant acceptance of smart field concept in the industry, there is still ambiguity not only on the incremental benefits but also the criteria and conditions of applicability technical and economic-wise. This study outlines the past, present and the dynamics of the smart oilfield concept, the techniques and methods it bears and employs, technical challenges in the application while addressing the concerns of the oil and gas industry professionals on the use of such technologies in a comprehensive way.
History of smart/intelligent oilfield development, types of technologies used currently in it and those imbibed from other industries are comprehensively reviewed in this paper. In addition, this review takes into account the robustness, applicability and incremental benefits these technologie bring to different types of oilfields under current economic conditions. Real field applications are illustrated with applications in different parts of the world with challenges, advantages and drawbacks discussed and summarized that lead to conclusions on the criteria of application of smart field technologies in an individual field.
Intelligent or Smart field concept has proven itself as a promising area and found vast amount of application in oil and gas fields throughout the world. The key in smart oilfield applications is the suitability of an individual case for such technology in terms of technical and economic aspects. This study outlines the key criteria in the success of smart oilfield applications in a given field that will serve for the future decisions as a comprehensive and collective review of all the aspects of the employed techniques and their usability in specific cases.
Even though there are publications on certain examples of smart oilfield technologies, a comprehensive review that not only outlines all the key elements in one study but also deducts lessons from the real field applications that will shed light on the utilization of the methods in the future applications has been missing, this study will fill this gap.
In this work we aim to enhance the sour-gas loading in acid-gas removal (AGR) systems, maximizing oil-production rate at the tertiary phase and enhanced oil recovery (EOR), and mitigating vented carbon dioxide (CO2) with minimal modification to the existing systems. We conducted a simulation study on the basis of a real natural-gas liquids (NGLs) plant and Qatari oil wells with a 390-MMscf/D feed of sour gas using HYSYS and ProMax process simulation tools to evaluate the novel configurations compared with a conventional AGR system.
The results show that the acid-gas loading improved from 0.48 to 0.81, and the amine circulation rate decreased by 40%, while maintaining the treated-gas quality specifications (4 ppm H2S, 1 mol% CO2). The required CO2 compression power for CO2-EOR decreased by 15.49%, and the oil production was enhanced by 1,360 B/D. In addition, 13.6 MMscf/D of CO2 is mitigated and used rather than vented.
The objective of this paper is to share Occidental Oman's Talent Management strategies, development programs, and the results achieved on the ground. The focus will be on three major pillars; (i) understanding the adopted talent management strategies/framework and the value chain as we materialize the strategies on ground, (ii) hiring strategies, and (iii) ensuring we are developing the required talent development programs to accelerate the learning and time to autonomy. To give the audience a better understanding of our adopted talent management strategy and our sustainable nationalization program, I'll present one of the successful heavy oil projects as a business case, the Occidental Oman Block 53 Mukhaizna Project. Block 53 is a heavy-oil field (approximately 15.5 API). An oil field of such nature requires a unique set of technology and equipment to get the oil from the ground. Accordingly, Occidental Oman constructed one of the world's largest and most advanced mechanical vapor compressors, also known as MVC. Considering that Mukhaizna is the only MVC in the region, and taking into account the unique technology/equipment utilized in the project, there was an understandable lack of knowledge and expertise in the local and regional market. As a result, Occidental Oman had to develop a hiring and skills development strategy to be able to commission and operate the project to achieve the required targets.