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.
Hegazy, Mohamed (M-I SWACO, A Schlumberger Company) | Sharma, Sunil (M-I SWACO, A Schlumberger Company) | Fares, Khaled (M-I SWACO, A Schlumberger Company) | ElBatran, Ahmed (M-I SWACO, A Schlumberger Company) | Dave, Alok (M-I SWACO, A Schlumberger Company) | Megally, Fady (M-I SWACO, A Schlumberger Company)
Lost circulation is a prominent problem in almost all fields of Saudi Arabia. Losses can vary from partial to total and sometimes also initiate other drilling related issues, such as stuck pipe, kick, and wellbore instability. These complexities make it paramount to cure losses as fast as possible to minimize non-productive time.
Conventionally, discrete pills formulated using a material blend with broad particle size distribution (PSD) are employed first as one of the more popular approaches for curing severe lost circulation. The lost circulation material concentration and PSD are increased in the pills based on loss rates, thus under severe and total loss conditions the pills require use of specialized pumping equipment, by-pass tools, and even the removal of the BHA. Unfortunately, dealing with severe losses in the Kingdom, success rates with these pills are very low. A solution for severe to total losses pumpable through a BHA was the operator’s wish.
In this paper, successful field applications proving the advantages of a new high-fluid-loss, high-strength (HFHS) lost circulation solution in different fields, formations, and sections will be covered in detail. The paper will also include operational best practices for mixing, pumping, spotting, and squeezing HFHS pills, lesson learnt, and recommendations for future applications.
Lost circulation events occur for a variety of reasons. These can be separated into two categories: filtrate losses into permeable formations and whole mud losses into (natural or induced) fractures, vugs, and faults. Lost circulation is one of the biggest contributors to non-productive time (NPT). Estimates of direct and associated costs run in to hundreds of millions of dollars globally (Ivan et al., 2003), including whole mud losses, cost of treatment, and lost time and tools.
Lost circulation has always been a big cause of concern for Saudi Arabian fields. Total losses are prevalent in top hole sections, but as high mud weights are not required in these sections, blind drilling provides an economical alternative; thus, operators avoid spending time to cure the losses. In mid sections, where drilling is done through Sulaiy and Arab formations, losses leads to high financial impact due to high mud weights required in these sections. The high cost/bbl of the lost fluid and the related NPT while curing the losses have pushed operators and service providers to look for a versatile solution.
Al-Hajri, Nasser M. (Saudi Aramco) | Al-Ghamdi, Abdullah A. (Saudi Aramco) | Al-Subaie, Fehead M. (Saudi Aramco) | Mujaljil, Salih (Saudi Aramco) | Al-BenSaad, Zakareya R (Saudi Aramco) | Srivastava, Abhiroop (Schlumberger) | Ahmed, Danish (Schlumberger) | Aiman Kneina, Mohammed (Schlumberger) | Molero, Nestor (Schlumberger) | Barkat, Souhaibe (Schlumberger)
Horizontal carbonate reservoir stimulation has attracted considerable attention in the past decade as one of the major areas for development in matrix stimulation engineering. Modern technologies have enabled technically suitable interventions in extended and even mega-reach wells. In the Middle East especially, carbonate field development strategies have used mega-reach wells as the main technique in achieving the highest possible reservoir contact. In such a case, coiled tubing (CT) intervention becomes a necessity.
With carbonate acidizing, since more than 50% of the matrix is soluble in acid, the objective is to bypass the damage and increase the productivity by creating new highly conductive channels called wormholes. The success of a treatment is a function of fluid penetration, acid reactivity, injection rate and diversion. To increase the success of the treatments, improvements have been made recently in injection rate and diversion using the latest technologies in CT intervention. The introduction of CT provides significant advantages in stimulation execution, yet imposes some challenges. Real-time downhole measurements using fiber optic telemetry have been used frequently to improve chemical diversion and fluid placement. However, pumping rates have been significantly limited to a maximum of 2.0 bbl/min when this technology is deployed.
Extensive engineering work was invested in solving this challenge. The main objective was to obtain the optimum diversion using downhole “point” and distributed measurements without sacrificing the high injection rates. In response to this need, modifications to the existing downhole measurement system were introduced enabling pumping of rates beyond 5.0 bbl/min. The key focus of the redesign was the repackaging of the downhole tools as well as the telemetry link to surface, resulting in expansion of the operating envelope of the technology.
Yard testing has been completed, and results have been encouraging. The solution has been piloted in the field, and a field case study showed remarkable injectivity improvement.
The Arabian Gulf, in Saudi Arabia, is a mature petroleum province. Asexploration moves from structural concepts to the stratigraphic domain,identifying petroleum system elements in areas with limited well controlbecomes imperative to cost-effective exploration. Explored areas are blessedwith reliable datasets (most significantly well data) that records subsurfacerock properties. In exploratory areas with very sparse well control, seismic isthe most appropriate data set currently available for approximating rockproperties. Therefore, finding reliable seismic attributes that correlate torock property variations in well logs holds the key to exploratory success.
This paper presents the results of a project undertaken to identify seismicattributes that differentiate between source and reservoir facies within thecarbonate Hanifa Formation in the Eastern Province of Saudi Arabia. A detailedanalysis of wireline logs from wells suggests that rock properties likevelocity, impedance, Lambda Rho and Mu Rho are higher in carbonate sourcefacies under consideration than their reservoir counterparts. Impedancecomputed from seismic inversion is found to be in consonance with that derivedfrom wireline log data. Projected facies are found to fit predictions of thegeological model in wells in the study area. Mapping of impedance in the 3Dseismic volume helps carry the interpretations from the known to the unknown.Acoustic impedance, derived from seismic inversion, thereby offers promise as atool for identification of petroleum system elements in areas with very sparsewells.
Our industry has embarked largely on implementing the intelligent field initiative in recent years, which is a clear indication of the surge to adapt to new methods, processes and workflows to manage existing and new fields. The capacity at which this technology was implemented worldwide is a sign of a strong buy-in from the industry that this technology will deliver on its promises in terms of maximizing hydrocarbon production, recovery, profits, or health, safety and environmental compliance.
Saudi Aramco is considered to be a leader in deploying and utilizing the intelligent field technology to maximize the value of hydrocarbon reservoirs. This paper discusses the implementation of intelligent field initiative in Saudi Arabian fields and particularly in the world's largest intelligent field, the Khurais complex. It highlights the huge infrastructure to measure and transmit data and to manage and control production in this field. As a result of the lessons learned from this experience, the classical reservoir management concepts are going through a major transformation to adapt to a fundamental change in data acquisition and production controls. Moreover, the engineers were faced with a new challenge in the reservoir monitoring process and overall field optimization, which requires a paradigm shift in analysis, interpretation, and decision making to maximize the value of the intelligent field. So far, the industry's efforts to utilize intelligent field technology are mainly focused at well level to optimize production rate and ensure target rate compliance. Saudi Aramco's efforts are going beyond the well level to optimize reservoir performance and enhance oil recovery. This paper illustrates some of those efforts, which resulted in a better understanding of well deliverability and reservoir connectivity.
In addition, this paper highlights the major challenges facing operating companies, to manage those fields. It provides methods and workflows to mitigate these challenges and maximize the value of intelligent fields and fully utilize the existing infrastructure and capabilities.
Introduction: Real-Time Reservoir Management
The first section of this paper deals with the definition of real-time reservoir management, which is essential to set the stage for discussing the value of intelligent fields. The benefits realized from intelligent field technology are highly correlated to the success of implementing real-time reservoir management. This section starts with a general definition of reservoir management, which is followed by a discussion on the evolution of the reservoir management process and the introduction of real-time reservoir management. Finally, it highlights Saudi Aramco's efforts to build four major layers to ensure successful implementation of real-time reservoir management.
The Tuwaiq Mountain and Hanifa formations contain both significant hydrocarbon reservoirs and world-class hydrocarbon source rocks. This paper focuses on the characterization of the source rocks within the formations by integrating core-derived geochemical data and well-log responses. The hydrocarbon source rock potential of these stratigraphic intervals in the Arabian intrashelf basin was evaluated using Rock-Eval pyrolysis and the Delta Log R method. Organic geochemical analyses of core samples for S2, total organic carbon (TOC), and hydrogen and oxygen indices were used to determine the quality of organic matter. Most of the source rocks are thermally mature and contain oil-prone Type-II kerogen. The Delta Log R method was used to obtain calculated TOC values to increase the coverage across the zone of interest (uncored intervals) and laterally at the uncored wells. Level of maturity (LOM) is one of the key required inputs for the Delta Log R method. The LOM was derived from predicted vitrinite reflectance values using heat flow distribution within the entire basin. A comparison of TOC values derived from the Delta Log R method with actual laboratory-measured TOC values from core samples shows a very good agreement. This allows confident application of this technique in calculation of TOC values in wells for which no core samples are available. The TOC and effective thickness fairway maps of the Tuwaiq Mountain and Hanifa source rocks generated from this method offer great insights for defining the source rock characteristics.
This article discusses the upstream development of Khurais field, referred to here interchangeably as the Khurais complex, consisting of several fields and reservoirs with a capacity of 1.2 million barrels per day (MMBPD) of Arabian Light crude. It describes the planning, execution and leveraging of technologies coupled with best industry practices to deliver the target rate while reducing the unit development cost, increasing the well productivities and expanding the reserves base. At the beginning of the project, a high resolution 3D seismic program was successfully performed to characterize the reservoir structure and geological features. Coupled with vertical-horizontal delineation wells, additional reserves were delineated and added to the development. To reduce the unit development cost, this article will show that the project utilizes a complex well architecture with a combination of maximum reservoir contact (MRC), multilateral, and horizontal wells, as well as smart completion (SC), smart electrical submersible pump (ESP), and passive inflow control devices to achieve and sustain the target rates. The development also sets the stage for technology leveraging in the future by drilling wells with large wellbores, allowing flexibility for the next-generation of complex well architecture while pursuing fit-for-purpose technologies through joint ventures and Saudi Aramco's Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC).
The article illustrates that the Khurais development is unique not only in terms of its size but also in terms of special technology applications, and its complexity with respect to the development of multiple fields and reservoirs with proper utilization of many complementing technologies. Through Saudi Aramco best practices, all of these are part of the development plan, which utilizes applications of advanced mathematical models in the form of multi-objective functions and probabilistic modeling techniques, such as Experimental Design and Monte Carlo simulations. The final development plan mitigates the development risk and optimizes oil off-take from different reservoirs and areas with respect to well placement, ESP design, depletion rates, injection production ratio, number of injectors and producers, pressure support, sweep efficiency, flood front conformance and oil recovery. The best practices also include real-time geosteering to ensure the horizontal laterals are directed through the best pay possible.
Qatif field is the first intelligent field in Saudi Aramco equipped with measurement, communication, control and software enabling semi real-time and automated asset management and field rate optimization. Qatif is fully automated with remote controls, due to its complex reservoir characteristics and fluids with high H2S concentration up to 16% (160,000 ppm). Difficulties were experienced with one of the main intelligent components of the surveillance systems, the Multiphase Flow Meter (MPFM), due to the H2S variations, which can reach up to 5% within the same reservoir.
Qatif field was developed with three producing reservoirs with API ranges from 28º to 42º due to the different reservoir characteristics and compartmentalization. The production from the three reservoirs is commingled inside the Gas Oil Separation Plant (GOSP) to produce blended Arab light crude. Measuring mechanism of the multiphase flow meters (MPFMs) is dependent on the accurate PVT properties of the fluids. PVT Reports based on black oil models were Initially used, but did not match the fluid characteristics due to the H2S presence in the produced gas in addition to the sulfur substance in the produced fluids, which has resulted in inaccurate water liquid ratio (WLR) measurements that was showing as high as 60% water cut on dry wells. Each MPFM is serving multiple wells from the three producing reservoirs. Without allocating the right rate for each single producing well utilizing the MPFM, it was very difficult to produce the blended Arab light crude that Saudi Aramco was committed to produce. To enhance the matching of fluid PVT characteristics and due to the limited number of wells with PVT analysis, generic PVT reports from simulation models were generated, then cross-checked with the output readings of the oil, water and gas rates with a three-phase portable separator in series with the MPFM. Separator test results almost matched the rates from the MPFM loaded with known PVT reports from wells and within an acceptable accuracy compared to the readings from wells with generic PVT reports.