Gas Migration through cement columns has been an industry challenge for many years. To control gas migration, high cement densities are required to successfully cement the high pressure formation. Formation gas/influx can migrate through the cement column resulting in gas being present at the surface.
Current high density cement formulations do not provide good gas migration prevention due to settling and increase in permeability. To solve the settling problem and reduce permeability of cement, intensive lab work was conducted earlier by
The objective was to develop novel cement formula containing a combination of solids with different particle size distribution to minimize cement porosity and prevent solids settling. Compared to conventional high density cement weighted up with hematite, the developed cement showed no signs of settling, better fluid loss control and improved resistance against gas migration in the lab.
Saudi ARAMCO has successfully trial tested their new developed cement formula (Gas Preventing Cement) in 5 wells in 2015 for 9 5/8" casings across high pressure formation to mitigate 9 5/8" X 13 3/8" Annular leaks. This is an effort to help in minimizing gas shut-in potential and safety risks due to casing-casing leaks. The new formula was applied with good cement returns to surface and good wellbore isolation according to the conducted well flowing test. In addition, loggings were run to ensure good bonding of cement. More high pressure gas wells will be cemented using this formulation.
Successful production from unconventional reservoirs requires expensive hydraulic fracturing operations that are not only costly but pose environmental and health risks if not managed properly. Optimized use of microseismic imaging is essential to control the hydraulic fracture operation, to minimize any possible environmental hazards introduced by fracturing, and to achieve cost efficiency.
An integrated workflow that incorporates advanced geophysical techniques is presented in this paper to enhance microseismic imaging of hydraulic fracturing in unconventional resources in Saudi Arabia. The use of surface seismic attributes is suggested to primarily minimize location uncertainties of microseismic events; whether downhole or surface receivers arrays were used. Secondly, coherence and edge attributes are used to highlight faults and seismic-scale fractures in seismic volumes, knowledge of which may favorably infer the "geomechanical" maximum horizontal stress direction; hence the main direction of fluid flow within targeted sediments and a preliminary conception of hydraulically induced fractures' direction of propagation. Moreover, knowledge of fault networks in reservoirs is vital to pinpoint potential barriers that may impact the growth of fractures, and their likely geometries.
Seismic attributes are combined with acoustic impedance inversion volumes, Vp/Vs and Poisson ratios to further enhance inferences to hydrocarbon bearing, and sediment brittleness. These methods can be used collectively to optimize multi-staged hydraulic fracturing of unconventional reservoirs, which will eventually lead to limiting stimulation to only selected "producible" sweet spots, thus minimizing the required number of "fracking" stages and associated environmental and financial concerns. These methods should also drive the use of more economic stimulation solutions using low-proppant, high-flow-rate, and water based treatments (
Horst, Juun van der (Shell International E&P) | Panhuis, Peter in 't (Shell International E&P) | Al-Bulushi, Nabil (Shell International E&P) | Deitrick, Greg (Shell International E&P) | Mustafina, Daria (Shell International E&P) | Hemink, Gijs (Shell International E&P) | Groen, Lex (Shell International E&P) | Potters, Hans (Petroleum Development Oman) | Mjeni, Rifaat (Petroleum Development Oman) | Awan, Kamran (Petroleum Development Oman) | Rajhi, Salma (Petroleum Development Oman) | Bakker, Goos
In the past decade, Fiber-Optic (FO) based sensing has opened up opportunities for in-well reservoir surveillance in the oil and gas industry. Distributed Temperature Sensing (DTS) has been used in applications such as steam front monitoring in thermal EOR and injection conformance monitoring in waterflood projects using (improved) warmback analysis and FO based pressure gauges are deployed commonly. In recent years
There are still improvements to be made in enabling Distributed Sensing infrastructure, such as handling and evaluation of very large data volumes, seamless FO data transfer, the robustness & cost of the FO system installation in subsea installations, and the overall integration of FO surveillance into traditional workflows. It will take some time before all these issues are addressed but we believe that FO based applications will play a key role in future well and reservoir surveillance.
In this paper we present a recent example of single-phase flow profiling using DAS. The example is from a long horizontal, smart polymer injector operated by Petroleum Development Oman (PDO).
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.
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.
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.
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.
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).
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.
At the early phases of EOR developments, small scale pilots are commonly used to obtain information of the EOR field development mechanisms. The lessons learnt from these early pilots are subsequently used to de-risk and improve the full field developments.
In initial phases, well and reservoir surveillance plays an important role to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to de-risk and optimise production and ultimate recovery from reservoirs significantly.
Successful projects are characterized by a high level of cross discipline integration.
This paper discusses the important field development decisions of Miscible Gas, and Chemical projects, that have been based on well and reservoir surveillance results that will be presented in this paper. A clear strategy is presented to select surveillance strategies dependent on the field development decisions that need to be taken.
Moreover, field case examples of these decisions are presented in the remainder of the paper.
For the chemical injection project in a clastic field a new workflow was developed to analyse well-tests of for polymer injection. The field management decisions to adapt rates, effective viscosities and change water treatment requirements are supported by an integrated modeling and surveillance effort. This fracture monitoring workflow plays a role in the regular pattern management evaluations to manage the field in a holistic manner.
Two examples of a miscible gas flood will be presented. In the first one, the pattern geometry of a miscible gas flood was changed from an inverted 9-spot to a line drive based on surveillance information. Additional development opportunities and reserves were identified through extensive surveillance, performance monitoring and data gathering pilots. In the second example, we present the field outline with a surveillance plan, with magnetic resonance and other new saturation tools. Moreover vertical conformance is demonstrated to be measurable through distributed temperature sensing.