During the process of Cyclic Steam Stimulation (CSS) variations in reservoir pressure and temperature occur changing the solubility of reservoir rock minerals in the formation water and therefore during production phase, produced water brings valuable information about dynamic characteristics of reservoir rock and fluid. Its analysis may provide an invaluable means for monitoring the reservoir. This paper describes the process of water analysis where results are interpreted on the basis of the principle that the solubility of minerals varies with change in pressure and temperature. This also shows the importance of water analysis as a key tool for reservoir monitoring in fields undergoing cyclic steam stimulation.
Water analysis is also used to optimize impact of produced water on Capex and Opex of oil production as water is required to be handled and disposed without impacting the environment, and is applied as troubleshooting tool to identify well problems and to validate log interpretations.
Field examples illustrate application of water analysis in i) mineralogical changes that takes place during CCS operation for reservoir monitoring and impact of steam on clays, ii) determining compatibility of injected steam with the formation water and compatibility of effluent with the formation water of disposal well, iii) surface facility design and water treatment before steam generation, iv) reservoir description and computing fluid saturation using resistivity of formation water and v) troubleshooting well problems, e.g. unanticipated water production because of channeling behind the casing and communication between the layers.
Paper discusses the importance of water analysis at each stage of CSS operation and its application in reservoir monitoring and describes field experience with water analysis in the surveillance of a CSS project.
Chowdhuri, Sankar (KOC) | Cameron, Peter (KOC) | Gawwad, Tarek A. (KOC) | Madar, Mohammad R. (KOC) | Sharma, Siddhartha Sankar (KOC) | AlMutairi, Moute'a Dughaim (KOC) | Rajagopalan, Vijay Shankar (KOC) | Chellappan, Suresh (KOC) | Al-Ajmi, Moudi Fahad (KOC)
Development in drilling technology allows horizontal and multilateral wells to increase hydrocarbon recovery and accelerate production from high water mobile reservoir by increasing the reservoir contact surface. In coning situations, such as production of oil reservoir with a bottom aquifer, multilateral wells reduce the coning affect and hence prove to be more cost effective. To address these challenges, first multilateral well with Level-4 junction combined with Inflow Control Device (ICD) was planned, designed and drilled in Upper Burgan Reservoir of Raudhatain Field, North Kuwait.
The Upper Burgan Formation is layered sandstone–shale sequence deposited in deltaic settings having very fine to fine grained marine influenced channel sand as reservoir rock. Geosteering and evaluating these wells is very challenging without using a proper LWD technology. Indeed, the resistivity anisotropy is a major issue, especially if it occurs with influence of other bed boundary effects like resistivity of adjacent beds or polarization horn effects. Water coning issues in the field makes it even worse to interpret the resistivity data as they become spiky. To overcome these challenges the drilling bottom hole assembly was designed in the way to include the distance to boundary and the new Multi-function LWD sourceless technology. The capture gamma ray spectroscopy and formation sigma in real time has improved the petrophysical evaluation of this complex resistivity environment with mixed lithology in wells that are difficult or even costly to consider TLC wireline logging.
The Lower Lateral of 2145' with 8½" hole diameter was drilled through very fine grained sandstone in UB3 Lower zone and completed with 5" open hole ICD. The Upper Lateral of 1757' was placed in UB3 upper zone having very good reservoir quality. This lateral was completed by 4½" open hole ICD. The production is comingled as the pressure difference between the two laterals was not more than 100 psi. The well operated under Electrical Submersible Pump (ESP) produced more than the estimated rate of oil during initial production.
The success of the well not only addressed the issues related to enhancement of oil production and premature water break through but also opens up a new chapter of drilling multilateral wells in coming days in Raudhatain Field, North Kuwait. The paper covers the main challenges while well placement during geosteering to stay in the best quality of reservoir rock in structural and depositional complex settings and with the smart completion design for increase oil production and rate of recovery.
This paper highlights the tremendous impact of real-time data transmission and visualization on hydraulic fracturing, also known as "fracing." Here, we will focus on tight reservoirs. Utilizing the advanced real-time visualization system with high-resolution data transmission enables the frac engineers to achieve promising results, and ensures effective decision making and data substantiation from real-time fracing centers at their base offices.
Saudi Aramco adopted single-viewer visualization solutions to support a wide range of different operations with a single system through which Aramco users can simultaneously monitor various activities, including drilling and post-drilling activities with ease. This solution was approved to support the high supremacy of hydraulic fracking operation and their requirements by attaining the high speed of data transmission and visualization at the rate of minimum one-second data. The data transmitted all the way from the rig site to the base monitoring centers and displayed on customizable templates to meet the requirements of the data visualization with real-time calculations.
The importance of real-time monitoring micro-seismic data is the key tool to determine the frequency of hydraulic fracturing during frac operations. This type of operation needs to be verified with the simulation models, and the whole range of complex operations is made possible with the advance technique to transmit real-time data. This real-time data was used for monitoring and treating wells at the most required rate of data availability at the base where complete optimization teams utilize different simulation applications to connect direct real-time data feeds, which are used to capitalize on the industry-standard well data transmission protocol (WITSML).
Raudhatain field located in North Kuwait produces hydrocarbons from over 230 wells into Gathering Center X with varying complex geometries, completions and downhole equipment. NK asset team is executing a project of modeling the entire NK production system starting with wells in Raudhatain field producing to GC-X, involving building models for the wells and the gathering surface network of flow lines.
There are numerous challenges that the NK asset team is facing in meeting production targets, including controlling water/gas breakthrough in horizontal wells. Mitigation measures include installation of inflow control devices (ICDs). Since inception a decade ago this proven technology has long been used in many oilfields around the world and is increasingly being installed in horizontal wells in Kuwait. To date there are several horizontal wells in Raudhatain field completed with ICDs.
Reservoir modeling and simulation approach is frequently used in the industry capturing the behavior of existing ICD wells. This approach uses conventional modeling tools that are typically more intricate and require expert skills in capturing the dynamic behavior of the wellbore and the reservoir which is less appealing to the operations and practicing engineers.
Limited with time and resources in this project, the NK team took a relatively simpler and fast approach in modeling existing ICD wells in Raudhatain field with the aim of enabling the engineers to capture the behaviour of the wells using existing production engineering tools at their disposal.
The approach can be summarized as follows: Establishing the well performance Modeling the individual ICD sections in accordance to the approximate flow distribution/geometry along the horizontal well Matching the well with well test data
Establishing the well performance
Modeling the individual ICD sections in accordance to the approximate flow distribution/geometry along the horizontal well
Matching the well with well test data
Key benefits of this approach are: Enabling the engineers to quickly model the ICD wells. Facilitated the use of existing tools to deliver engineering models fit for use in the production system. Serves the purpose of high level modeling of complex ICD wells and in the future this exercise will certainly be undertaken to capture wellbore hydraulic effects. ICD well models are timely added into the gathering network which would otherwise have been delayed using a conventional method.
Enabling the engineers to quickly model the ICD wells.
Facilitated the use of existing tools to deliver engineering models fit for use in the production system.
Serves the purpose of high level modeling of complex ICD wells and in the future this exercise will certainly be undertaken to capture wellbore hydraulic effects.
ICD well models are timely added into the gathering network which would otherwise have been delayed using a conventional method.
Verlaan, M. L. (Shell Canada Limited) | Hedden, R. (Shell Canada Limited) | Castellanos Díaz, O. (Shell Chemicals Americas Inc) | Lastovka, V. (Shell Chemicals Americas Inc) | Giraldo Sierra, C. A. (Shell Chemicals Americas Inc)
In recent years, the addition of a hydrocarbon condensate (C4 to C20) to steam operations (such as CSS and SAGD) in heavy oil and bitumen reservoirs has emerged as potential technology to improve not only oil recovery and but also energy efficiency. Shell has extended the idea of solvent addition to a steam drive process, applied it for the first time in the Peace River area in Canada, and obtained evidence of oil uplift in the patterns where solvent was injected. However, piloting this new technology in a brown field had many challenges, especially when evaluating its main economic factors: production increase and solvent recovery.
To overcome these challenges, emphasis was put on experimental design, data acquisition and quality, and production surveillance. The pilot conditions were designed to increase the probability of success on the two economic factors aforementioned within a short period of time. The assessment of the pilot required that all production streams (emulsion and casing vent gas) were metered and frequently sampled to measure their respective compositions. Cross calibration of metered and sampled water cuts was essential in obtaining conclusive production uplift data. Automatic proportional samplers were successfully deployed under these challenging conditions to obtain representative samples. Due to the overlap of solvent and bitumen components, special attention was taken to allocate hydrocarbon production into bitumen and solvent. New in-house developed algorithms were tested to accurately calculate this split.
The addition of a 4 month concentrated slug of solvent in two steam drive patterns resulted in a significant production uplift when compared to two adjacent patterns with steam-only injection. Solvent recovery is still ongoing and exceeds original expectations. Frequent sampling allowed the detection of several trends, including bitumen composition changes during solvent injection and solvent fractionation in the reservoir.
Carbonate reservoirs are known for complexity to oil recovery industry, one reason is the dual-porosity pore system. In macroporosity regions where pores are mostly effective for fluid flow and therefore viscous flow will play a role in oil extraction, while in microporosity regions contribution of pores to permeability is very limited and results in a large amount of residual oil entrapment. The purpose of this paper is to investigate the response characteristics of diffusion to porosity (include percent fraction and pore size ratio of macro- and microporosity) and permeability. Then with the help of permeability to evaluate the efficiency of CO2 diffusion for oil extraction from different porosity composition core plugs.
In order to achieve this objective, we use integrated carbonate core samples by pore structure characterization to study the feasibility of diffusion macro- and micropore regions. First, SEM and MICP experiments were introduced to characterize the bimodal pore systems, these results were combined with permeability measurement values as basic parameters for evaluation. Then the response characteristics of CO2 diffusion to macro- and microporosity will be described by the performance of CO2 injection for oil recovery with dual porosity carbonates.
With the result the first observation was the dual effect of macroporosity that it lowers the resistance for fluid flow and meanwhile reduces the exposure duration for CO2 to diffuse into the microporsoity regions. Furthermore, percent fraction, tortuosity and ratio of pore size between macro- and microporosity are critical parameters for CO2 diffusion. Also with different dual porosity component core plugs, various ultimate oil recoveries were acquired and all recovery curves were divided into two different parts that contributed by viscous flow and diffusion respectively. Through comparison the different diffusion performance in various dual porosity core plugs, response characteristics of CO2 diffusion to macro- and microporosity were finally concluded.
Acquire the knowledge of CO2 diffusion response characteristics to macro- and microporosity makes oil extraction from microporosity regions which have limited contribution to permeability possible. It shows an optimistic prospect of oil recovery by diffusion mechanism which ever been neglected and provides one more option for EOR method design in low permeable reservoirs. In addition, suggestion will be presented to extract oil effectively using CO2 injection in case of high percent fraction of microporosity reservoirs.
Bahman, Hussasin Ali (Kuwait Oil Company) | Hajeyya, Abdullah Khalid (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Mukherjee, Pradip Kumar (Kuwait Oil Company) | Al-Sabea, Salem Hamad (Kuwait Oil Company) | Mohammed Ali, Farida (Kuwait Oil Company)
Geo-steering is a very critical part of today's field development economics, our production targets are getting more complex, thinner oil columns, which need more complex geo-steering, continual improvement needed in People, technology and processes. Drilling a well at an angle other than vertical can obtain more information by hitting the production targets and stimulate reservoirs in ways that cannot be achieved with a simple vertical well which became a valuable ability in oil business. To augment this aspect Kuwait Oil Company has established Geo-steering Center (
The establishment of Geo-steering control Room in FD (S&EK) is an outcome because of constant supervision and direct guidance by manager of Field Development South and East Kuwait, which added a new dimension to drilling the modern horizontal wells in the Greater Burgan Field. The team of Geologists of FD (S&EK) in this collaboration center ensures that horizontal wells are steered correctly and safely to their final targets.
The Geo-steering center can be operated 24 hours a day if require. Each geologist may be responsible for as many as 3 wells in different fields (BG, MG & AH) and different reservoirs. Like driving, geo-steering requires constant attention and dedication all the time. The center recently moved into a new and expanded facility that is equipped with the latest in visualization, communication and computer technology in order to properly place and geologically navigate us with many complex horizontal wells path in Greater Burgan field. Geo-steering horizontal wells can be done remotely from the center, with data coming into the center from more than one well at any given time. For every well, Logging-While-Drilling (LWD) sensors near the drill bit send information about the Lithology and directional survey of the well to the control unit at the rig from where data is then transmitted by satellite to the geo-steering center. The team developed software instantly can load the data so geologists can see on their workstations the LWD and trajectory data to determine where the drill bit is in relation to the drilling plan and the reservoir target.
Within the framework of reservoir management streamline simulation finds one of its typical applications as one of the effective tool to improve gasflood and pressure maintance performance. Streamlines provide an instantaneous visualization of flow patterns as a function of reservoir heterogeneity. Additionally they also provide an estimation of the well allocation factors (WAFs) between injection and producing wells. Such information is a default outcome from streamline models but not from finite difference simulation and it is particularly useful in optimizing and balancing well patterns and field scale injection rates. However finite difference simulation has the advantage of implicitly taking into account all the details of an existing simulation model, especially advanced well management strategy. In this paper we demonstrate a straightforward workflow for optimizing injection rate based on a comprehensive analysis of two key parameters: injector efficiency (IE) metric and WAFs. The optimization approach consists of a three step procedure starting with streamline analysis using commercial software which combines the power of finite difference simulators and streamline technology to derive streamlines from the flux field generated by the finite difference simulation that represent a snapshot of the flow pattern within the reservoir, well drainage region information and fluid allocation changes with the flood progression. Second using a simple analytical calculation to compute weighting factors for injection/production rate targets from a derived ranking of the wells (IE). Finally reallocation of injected fluid volumes from low-efficiency to high-efficiency injectors improves volumetric displacement and sweep efficiency in the less swept areas of the reservoir. The application of this workflow is demonstrated with a real-field example of an onshore tight sandstone reservoir where the pattern balancing has led to incremental production of 3.5 % over the 5 year forecast in which the IE average of the field is the benchmark for whether more or less injection volumes were required while obeying facility constraints.
Electrical submersible pumps (ESP's) downtime is one of the most significant concerns that affect the oil production sustainability. Various defects as electrical trips, mechanical issues, under or over load trips and manual shut off are keeping the pumps off operation that would suspend the well productivity. The downtime of ESP's generized by generators globaly is exceeding an average of total 2 days per well from a population of 400 pumps. This is directly reducing the total daily production. The objective is to reduce the operational downtime by 50% after allocating the most marking defects to increase the pump's spinning time and maintain the wells’ production.
Statistical study using the Six-sigma procedures is employed to accomplish the downtime reduction. The problem is defined as reducing the ESP's downtime by 50%. The spinning hours are measured in daily bases from 400 wells and the downtime is calculated. Moreover, each defect is categorized to a main reason branch. The branches are mainly consisting the reservoir characterizations and the formation type. In addition to that, the data is analyzed using the ANOVA analysis road map and the hypothesis testing procedures.
The analysis showing that most of the defects are electrical ones, that is because of using diesel generators to energize the pumps. An improving process is encountered to overcome this problem by substituting the generators with the government electricity. In the other hand, high amount of defects are considered as reservoir effects while the pumps are tripping because of under or over load. The main reason behind this kind of pumps’ tripping is the pump design and the high water cut of the well. An appropriate pump design procedures are organized to reduce this kind of defects. Also, optimization practices are developed to set the right pump situation that would enhance the well productivity and minimize the operational downtime.
In order to control the ESP's operation, several monitoring methods and applications are used for taking actions toward any abnormal pump behavior as V-Monitor, SCADA and daily ESP reports.
Glasbergen, Gerard (Shell Global Solutions International) | Wever, Diego (Shell Global Solutions International) | Keijzer, Efraim (Shell Global Solutions International) | Farajzadeh, Rouhi (Shell Global Solutions International)
Polymer flooding is an attractive option in hydrocarbon maturation plans. Several successful polymer floods and pilots have been implemented. One of the risks in polymer flooding is loss of injectivity. The consequences of loss of injectivity can be large. In conditions where matrix injection is required, reduction of injection rate may result in a much slower propagating polymer front and consequently later arrival of the anticipated oil bank eroding on the economic value of the EOR process. In extreme cases it can even lead to loss of the injector. Under fracturing conditions the loss of injectivity may be less noticeable, but it can lead to out of zone fracturing or fractures that grow too much in size and cause shortcuts to the producers or affect future infill well drilling.
Reduction of injectivity is a generic concern in conventional waterfloods and can play an even larger factor when adding polymer to the waterflood. The increased viscosity of the injected polymer solution is the most obvious reason for an anticipated decrease in injectivity, but also other mechanisms can have an impact. These mechanisms include excessive polymer adsorption and associated permeability reduction, filtration of impurities in the polymer solution, fluid incompatibilities or reduced water quality.
In this paper we will discuss the various causes for loss of injectivity and propose a structured approach for the associated prevention and mitigation options. Prevention includes (1) selection of the most appropriate polymer type; (2) best practices for preparation of the polymer solution; (3) safeguarding the water quality; and (4) enabling options for mitigation in case excessive injectivity loss is observed. The remediation step includes (1) the identification of the root-cause of an apparent injectivity problem; (2) the design of an appropriate clean-up treatment; (3) monitoring of the operation; and (4) implement measures to avoid repetition of the problem. We will include an overview of the preventive and mitigation options for the different causes of injectivity decline in polymer floods.