A comprehensive study on wormholing has been conducted to improve the understanding of matrix acidizing in carbonate reservoirs. This work is a continuation of previous work (
A series of small block tests and one large block test under geomechanical stresses has been conducted to characterize wormholing in outcrop chalk samples. In addition, field data including acid pumping data as well as post-stimulation pressure falloff data has been collected and analyzed to evaluate stimulation effectiveness. Pressure buildup data from stimulated wells has also been analyzed to evaluate the sustainability of the acid induced skin benefits. Production logging data has been used to investigate whether created wormhole networks have remained stable or have collapsed under production stresses. To statistically analyze the data more comprehensively, the new data was also compared to the data from other field data available in the literature.
The following conclusions are drawn from an analysis of the laboratory data and field data: 1) a skin value of −4 is achievable in carbonate reservoirs by matrix acidizing, 2) the negative acid skin is relatively stable under production stresses, 3) the wormhole penetration model is proven to successfully simulate matrix acidizing processes in both laboratory scale and field scale work, 4) the small and large block laboratory tests re-confirmed wormholing efficiency which was discussed as a scale effect in previous studies, 5) an understanding of the possible range of wormhole penetration has allowed us to improve field acid treatments and reduce the risk of connecting to water.
This comprehensive study includes acid linear core flooding tests, small block tests, large block tests and field measurements to thoroughly analyze acid wormholing in carbonate rock. The database can be very useful information for understanding, benchmarking and optimizing future completion/stimulation design.
The present work summarizes the experiences and lessons learned around the deployment of the first Collaborative Work Environment (CWE) at the Loma Campana field, producer of the Unconventional formation Vaca Muerta in YPF SA, Argentina. In the context of the development of the first Unconventional field in Argentina, it was decided to telesupervise and automate all the facilities and wells. It was decided to create a centralized decision support centre (DSC) to manage the entire field operation, and to optimize the production in real time. Despite the technological capabilities of the telesupervision tools, there was an opportunity to improve online diagnosis and the process of decision-making for well optimization based on real-time information and data from the field.
This paper presents studies performed to optimize the operation of the artificial lifting system, Plunger Lift, in wells producing unconventional oil in the Vaca Muerta Formation, Unconventional Region, YPF S.A., Argentina. The field has more than 280 wells equipped with Plunger Lift. Most of them are instrumented, and automated, telesupervised. Despite the level of technology deployed, both in the field and in SCADA systems, the dedication of specialized production engineers was necessary to study the wells on a daily basis and in real time, implementing exception handling, in order to detect early warnings and assess opportunities for optimization. On the basis of experience in the operation and optimization of this extraction system and the work of multidisciplinary teams, diagnostic and decision making flowcharts were elaborated and then considered as early warning algorithms in SCADA control panels. This paper presents the results of these studies and the benefits obtained.
ABSTRACT: Carbonate strata are unique in that sediments can become lithified soon after deposition and prior to burial or loading (e.g., by marine or meteoric cementation). The rocks that develop have appreciable strength and cohesion that enable brittle failure under the influence of gravity. Conditions of increased effective tensile stress state can develop along steep-walled carbonate shelf margins and carbonate buildups. Marine and/or meteoric processes lead to the development of early mechanical property contrast between different facies. Some facies are mechanically competent (i.e. susceptible to brittle failure) while other facies experience ductile deformation via compaction. It is challenging to isolate features that are only related to early deformation in both outcrop and subsurface settings from those that occur from burial, uplift, and tectonism. To address this challenge, we present a forward numerical modeling approach using the finite-discrete element modeling code ELFEN to simulate these early deformation processes in carbonate systems. This modeling approach requires an initial geometry, initial rock properties, gravitational loading, and failure criteria. Bathymetry data of a modern example and a digital outcrop model of ancient rocks guides initial model geometry. Initial rock mechanical properties were measured by uniaxial compressive and Brazilian tests from collected modern and ancient rock samples. Failure criteria are assigned based on expected deformation behavior (i.e., brittle or ductile). Grain-rich carbonates and reef builders are prone to in situ early cementation and are expected to behave in a brittle manner and thus are assigned a Mohr-Coulomb with a rotating Rankine crack failure model. Soon after deposition mud-rich carbonate facies are expected to be prone to compaction and thus are assigned a modified CAM clay model that allows for compaction and porosity loss with increasing gravitational load. Modeling results are useful in determining most important variables to early fracturing and provide fundamental understanding of early deformation processes in strata that are known fractured carbonate reservoirs.
Syndepositional fracture and fault development has been documented in carbonate systems where lithification can commonly occur by meteoric and marine cementation prior to burial (e.g., Della Porta et al., 2004; Frost and Kerans, 2009; Kosa and Hunt, 2006; Verwer et al., 2009). These fracture and fault networks dictate early permeability anisotropy and influence subsequent diagenesis and deformation patterns (Budd et al., 2013; Frost et al., 2012). Syndepositional fractures can be a major contributor to permeability and hydrocarbon flow in giant carbonate reservoirs (e.g., Albertini, et al., 2013, Collins et al., 2013; Fernandez- Ibanez et al., 2016). Several challenges impede complete characterization of such fractures including insufficient sampling from the subsurface, outcrop quality, and overprinting by subsequent deformation or diagenesis. Here we address this challenge by a numerical modeling approach in which we simulate early fracture development in response to gravitational forces.
With a large base of mature assets and the development of the Kashagan field, it is a good time to look for resources that will drive and sustain production levels for future generations. The oil and gas industry has a history of building reserves through frontier exploration, near-field exploration, and building reserves in existing reservoirs, through better definition of the reservoir and application of advanced technologies. All of these opportunities are present in the Republic of Kazakhstan: there is the enigmatic deep carbonate resource which is the focus of the ambitious Eurasia project; the further definition and development of Kazakhstan’s supergiants which can make large additions to their proven reserves; opportunities for nearfield exploration building upon existing infrastructure; and a large base of older producing fields which can be sustained through improved/enhanced oil recovery and new business approaches. The effort to add reserves in all of these areas is key to bringing on future production over the short, medium and long term. Topics to be addressed by speakers: Frontier exploration: The Eurasia Project Near field exploration In field reserves development Enhanced/increased oil recovery New business models Speakers: Kurmangazy Iskaziyev, JSC KazMunayGas Exploration Production Baltabek Kuandykov, Meridian Petroleum Askar Munara, Ministry of Energy, PRMS Bakytzhan Kaliyev, KPO Paolo Emilio Spada, ENI 13:30 - 14:30 Lunch 14:30 - 16:00 Technical Session 1: Formation Evaluation and Petrophysics Session Chairpersons Ahmed El-Battawy, Schlumberger and Assel Salimova, Baker Hughes Formation Evaluation and Petrophysics are key integrating disciplines within geosciences applied to finding and developing hydrocarbon resources.
Schedule Session Details Expand All Collapse All Filter By Date All Dates Sunday, November 12 Monday, November 13 Tuesday, November 14 Wednesday, November 15 Thursday, November 16 Filter By Session Type All Sessions Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Training Course/Seminar Sunday, November 12 08:00 - 17:00 Production Optimisation System Instructor(s) Atef Abdelhady The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. Learn More 08:00 - 17:00 Practical Depth Conversion and Depth Imaging for the Interpreter Instructor(s) Pavel Vasilyev Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process. Participants will gain an understanding of depth conversion methodologies and QCs for validity of methods used. Learn More 08:00 - 17:00 Marginal Field Development and Optimisations Instructor(s) Abdolrahim Ataei Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. This session will show how chip technology has resulted in a miniaturised Electron Paramagnetic Resonance (EPR) spectrometer for online monitoring of asphaltenes (a chemical that clogs oil wells). The EPR sensor technology developed in the laboratory has been successfully deployed in major oil and gas fields across the world. This technology is used to monitor the concentration of asphaltenes in real-time and to minimise the use of environmentally hazardous chemical inhibitors in energy production. Employee suggestions for improvement cover a wide variety of topics such as economic efficiency, productivity, safety, operability, environmental friendliness, and to a greater or lesser extent, has led to efficient and improved operations.
The objective of this paper is to describe innovative process and tool developed for gas flaring reduction through Plant Optimization in order to meet state regulations.
According to Republic of Kazakhstan Laws, flaring of any substances during oil & gas operational activities needs to be logged and reported. Kashagan Field facilities are extensive, using approximately 260 valves connected to 2 Onshore and 3 Offshore Flare stacks
Over a reporting period, a valve can be opened and closed multiple times. Based on characteristics of the valve (valve type, pressure differences, valve opening percentage), the volume can be estimated for each release of gas (i.e. Flaring Event).
The following are the challenges that NCOC faces during flaring: Reasons for a flaring event need to be captured and the flaring events need to be managed to properly report the Flaring data against license constraints. Estimated volumes should be reconciled with calibrated measurements of total (at Flare Stack) flare volume taken from calibrated meters, entered in Hydrocarbon Accounting System (Tieto EC System). Composition needs to be derived from flare gas sources (valves).
Reasons for a flaring event need to be captured and the flaring events need to be managed to properly report the Flaring data against license constraints.
Estimated volumes should be reconciled with calibrated measurements of total (at Flare Stack) flare volume taken from calibrated meters, entered in Hydrocarbon Accounting System (Tieto EC System).
Composition needs to be derived from flare gas sources (valves).
Temperature and Pressure data to calculate Flaring Volumes are taken from Real-time Historian (OSIsoft PI System). This calculated data is reconciled against actual Flare meter value from EC. In the end, we have reconciled actual data for each valve to report to the Government bodies.
Flare events reporting is very critical for oil & gas business due to high environmental impact that costs North Caspian Operating Company N.V. (NCOC) considerable amount of money. Precision and accuracy of flare compositions reporting improves cost effectiveness. In future, this kind of analytics approach can be implemented for surveillance and reporting of another Oil & Gas operations outcome, water usage and disposal.
For the last decades, continuous global trend towards more stringent safety, commercial and environmental specifications kept processing sour natural gas containing acid gas such as H2S and/or CO2 a growing challenge. If mercaptans are present in the sour natural gas, the limited mercaptans absorption capacity of the well known alkanolamine solvents can be a major problem. The operating companies have to upgrade their production units to comply with these specification and environmental constraints evolutions. Additional treatment steps are often required to achieve the total sulfur specification in the sales gas, adding process complexity and further increasing cost.
An efficient solution to solve the problem would be to replace the usual alkanolamine aqueous solvent by a hybrid formulation allowing simultaneous removal on mercaptans and acid gases. This approach has been rarely considered because of the side effects of traditional hybrid solvents: hydrocarbon co-absorption, negative impact on the downstream sulfur recovery units. It may be necessary also to replace the internals of the absorber column in the Acid gas Removal Units.
To address this issue, TOTAL is now using a new dedicated hybrid formulation since 2007. This new solvent has been developed by TOTAL by taking advantage of its intensive know-how and experience in gas processing. The hybrid solvent is obtained by addition of a physical component into a generic alkanolamine-water solvent. The final solvent composition is determined to optimize mercaptans removal and minimize hydrocarbon coabsorption, without affecting acid gas removal capabilities.
Without any plant modification, this hybrid solvent can be implemented in existing unit to remove mercaptans with the acid gases, with no detrimental impact on downstream SRU. It allows operating cost reduction of the existing downstream units. Last but not least, the energy consumption of the acid gas removal units can be lowered by 10- 15%.
This paper presents several applications cases where the benefit of using the hybrid solvent is demonstrated.
Many but not all Oil & Gas operators develop company rulesets for Quantitative Risk Assessments (QRAs). For those that do, it is to ensure a consistent and high standard approach across all company assets, aiming to achieve a balance between modelling simplification and complexity. A QRA ruleset has been developed for the Kashagan field in Kazakhstan by the North Caspian Operating Company NV (NCOC), with the purpose of addressing the specific challenges associated with quantifying the risk of toxic releases from high-pressure, high-H2S content pipelines. This paper summarises the analytical approach given in the ruleset, and explains how it was developed, by bringing together the most up-to-date guidance available in the industry.
The main themes presented in this paper are: methodologies used to assess H2S risks to the general public, including the effect of concentration fluctuations and the choice of averaging time; the choice of dispersion model for far-field dispersion; and defining appropriate ‘source terms’ for the dispersion modelling in order to account for the effect of ground cover on buried pipelines and to allow the full-bore ‘crater’ releases to be characterised more realistically. Calculating the probability of releases, especially those for the largest full bore releases, is another important consideration.