At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
The Middle Minagish Oolite Formation is 450 to 550 feet thick interval of porous limestone reservoir, composed of peloidal/skeletal grainstones with lesser amount of packstone, oolitic grainstone, wackstone and mudstone in Umm Gudair field, West Kuwait. It is characterized by small scale reservoir heterogeneity, primarily related to the depositional as well as diagenetic features. Capturing reservoir properties in micro scale and its spatial variation needs special attention in this reservoir due to its inherent anisotropy. Reservoir properties will depend on the level that we are analyzing on reservoir (millimeter to meter scale). Here we used Electrical Borehole Image (EBI) and Nuclear Magnetic Resonance (NMR) to capture small scale feature of Umm Gudair carbonate reservoir and compared them with core data
In present work, reservoir properties (including texture, facies, porosity and permeability) interpreted by the EBI shows good match with NMR driven properties and core data. Textural changes in image logs also match well with pore size distribution from NMR logs. Further highly porous zones which are considered either due to primary porosity or vugs match with larger pores of NMR logs and these corroborates with also core derived porosity. A good match has been observed between EBI, NMR and cored derived porosity. Permeability calculations have also been made and compared with core data. A detail workflow has been developed here to interpret reservoir properties on un-cored wells, where only low vertical resolution data is available. This technique is quite useful to identify the characters and mode of origin highly porous zones in reservoir section which are generally not identifiable by low resolution standard logs. This workflow will allow us to interpret the heterogeneity at high resolution level in un-cored wells, as results are validated with integration of EBI, NMR and core data.
Blunt, Martin Julian (Imperial College) | Al-Jadi, Manayer (Kuwait Oil Company) | Al-Qattan, Abrar (KOC) | Al-Kanderi, Jasem M. (Kuwait Oil Company) | Gharbi, Oussama (Imperial College) | Badamchizadeh, Amin (CMG) | Dashti, Hameeda Hussain (Kuwait Oil Company) | Chimmalgi, Vishvanath Shivappa (Kuwait Oil Company) | Bond, Deryck John (Kuwait Oil Company) | Skoreyko, Fraser A. (CMG)
The Magwa Marrat reservoir was discovered in the mid-1980s and has been produced to date under primary depletion. Reservoir pressure has declined and is approaching the asphaltene onset pressure (AOP). A water flood is being planned and a decision needs to be taken as to the appropriate reservoir operating pressure. In particular the merits of operating the reservoir at pressures above and below the AOP need to be assessed.
Some of the issues related to this decision relate to the effects of asphaltene deposition in the reservoir. Two effects have been evaluated. Firstly the effect of in-situ deposition of asphaltene on wettability and the influence that this may have on water-flood recovery has been investigated using pore scale network modes. Models were constructed and calibrated to available high pressure mercury capillary pressure data and to relative permeability data from reservoir condition core floods. The changes to relative permeability characteristics that would result from the reservoir becoming substantially more oil-wet have been evaluated. Based on this there seems to be a very limited scope for poorer water flood performance at pressures below AOP.
Secondly the scope for impaired well performance has been evaluated. This has been done using a field trial where a well was produced at pressures above and substantially below AOP and pressure transient data were used to estimate near wellbore damage "skin??. Also compositional simulation has been used to estimate near wellbore deposition effects. This has involved developing an equation of state model and identifying, using computer assisted history matching, a range of parameters that could be consistent with core flood experiments of asphaltene deposition. Results of simulation using these parameters are compared with field observation and used to predict the range of possible future well productivity decline.
Overall this work allows an evaluation of the preferred operating pressure, which can drop below the AOP, resulting in lower operating costs and higher final recovery without substantial impairment to either water-flood efficiency or well productivity.
The North Kuwait Jurassic Gas (NKJG) reservoirs are currently under development by KOC. The fractured carbonate reservoirs contain gas condensate and volatile oil at pressures up to 11,500 psi with 2.9% H2S and 1.5% CO2. Currently around 20 active wells are producing to an Early Production Facility (EPF-50) that falls short of achieving the desired capacity and capability to handle production efficiently.
To understand wells and field performance, an integrated system model comprising of wells, flow line and gathering system separator network was created. The setting up a model and its use is an integral subset of WRFM (Wells, Reservoir and Facilities Management) process that is essential for effectively managing the current asset and for further field development.
The application of the model is to be an enabler for wider implementation of the WRFM process in KOC and a tool to meet the following objectives:
The model has shown close approximation with field metered production and is already achieving many of its desired objectives.
This paper describes the use of integrated nodal analysis model to generate data gathering and well intervention opportunities not only to operate the facilities efficiently but understand well and reservoir behavior for input to full field development plan.
Exploration activity during the last ten years, targeting Jurassic carbonate reservoirs in North Kuwait (Fig 1), has culminated in the discovery of six major tight gas condensate fields, encompassing an area of about 1,800 sq km with a reservoir gross thickness of about 2,200 ft. These fields are the first free-gas fields in Kuwait, which were put on early production during 2008. The reservoirs are characterized with dual porosity matrix system, dominated by low porosity and permeability, in deep HP/HT conditions, with wide variety of hydrocarbon fluids ranging from volatile oil to gas condensate with sour gas. Typical per well production rates are up to 5,000 BOPD/BCPD and 10 MMSCFPD, making them an excellent commercial success.
Turkey, Laila (KOC) | Hafez, Karam Mohamed (KOC) | Vigier, Louise (Beicip) | Chimmalgi, Vishvanath Shivappa (Kuwait Oil Company) | Dashti, Hameeda Hussain (Kuwait Oil Company) | Datta, Kalyanbrata (KOC) | Knight, Roger (KOC) | Lefebvre, Christian (Beicip-Franlab) | Bond, Deryck John (Kuwait Oil Company) | Al-qattan, Abrar (KOC) | Al-Jadi, Manayer (Kuwait Oil Company) | De Medeiros, Maitre (Beicip) | Al-Kandari, Ibrahim (Kuwait Oil Company)
A pilot water flood was carried out in the Marrat reservoir in the Magwa Field. The main aim of this pilot was to allow an assessment of the ability to sustain injection, better understand reservoir characteristics. A sector model was built to help with this task.
An evaluation of the injectivity in Magwa Marrat reservoir was performed with particular attention to studying how injectivity varied as injected water quality was changed. This was done using modified Hall Plots, injection logs, flow logs and time lapse temperature logs.
Data acquisition during the course of the pilot was used to better understand reservoir heterogeneity. This included the acquisition of pressure transient and interference data, multiple production and injection logs, temperature logging, monitoring production water chemistry, the use of tracers and a re-evaluation of the log and core data to better understand to role of fractures.
A geological model using detailed reservoir characterization and a 3D discrete fracture network model was constructed. Fracture corridors were derived from fractured lineaments interpreted from different seismic attribute maps:
A sector model of the pilot flood area was then derived and used to integrate the results of the surveillance data. The main output is to develop an understanding of the natural fracture system occurring in the different units of the Marrat reservoir and to characterize their organization and distribution. The lessons learned from this sector modeling work will then be integrated in the Marrat full field study.
The work described here shows how pilot water flood results can be used to reduce risk related to both injectivity and to reservoir heterogeneity in the secondary development of a major reservoir.
Hruška, Marina (Chevron Energy Technology Company) | Bachtel, Steven (Chevron Energy Technology Company) | Archuleta, Bonny (Chevron Energy Technology Company) | Skalinski, Mark (Chevron Energy Technology Company)
Here the nodule background consists of points at which evaporite flag is zero. These properties (except for the vertical proportion of evaporite) were averaged vertically over those depth samples in the image segment where the corresponding property being averaged is not zero. Use of this selected average rather than the segment average is needed for identification of the facies with common evaporite nodules, because nodules may be scattered and not present at every sampled depth. Individual nodules were identified at a given depth of the FMI by finding the breaks in a series of bright points in the image generated from the evaporite flag. Here, the gap between pads is not considered a break, to allow a possibility of nodules larger than the sensor pad.
Al-Farhan, Farhan A. (Kuwait Foreign Petroleum Exploration Co) | Gazi, Naz H. (Kuwait Oil Company) | Al-Humoud, Jamal (Kuwait Oil Company) | Tirkey, Naween (Kuwait Oil Company) | Haryono, Rafiq (Kuwait Oil Company)
Interference testing, although primitive in terms of its introduction and idea to the petroleum industry, still stands to this day as one of the most cost effective and efficient ways of confirming communication and evaluating reservoir properties between wells. Similarly, a pressure build-up is one of the most accurate ways of estimating dynamic reservoir parameters surrounding the well, providing that the shut-in of the well is allowable. On the other hand, a drawdown test is not usually recommended due to the instability of the flow rate, and hence, the uncertainty in the parameter estimation when analyzing the transient of the pressure drawdown. In this project, due to production constraints a drawdown test was run for the active horizontal well as a substitute to the pressure build-up. It was therefore decided to couple the drawdown test with an interference test so as highlight the subsurface uncertainties. In order to achieve these objectives, careful design and operational coordination between the different asset teams and contractors is crucial to obtain interpretable and useful data.
Water production was observed in some of the nearby wells, and therefore communication between the horizontal well and the surrounding wells needed to be verified. The main objective of this project was to evaluate the reservoir parameters and connectivity surrounding the important horizontal well. In this test, the horizontal well was the active well in a five well interference test. The results of the test indicated different pressure behaviors seen from the observation wells corresponding to the pulse created by the horizontal well. Communication was established in some of the wells, whereas, faults were also verified in the surrounding regions. In addition, the drawdown analysis of the horizontal well showed all the flow regimes that relate to a horizontal wells' signature as well as boundary behavior which coincide with the interference test results. The results of the drawdown analysis indicate the possibility and accuracy of conducting a pressure transient analysis using this method without being constrained with production objectives, and hence not shutting the well in.
Padhy, Girija Shankar (Kuwait Oil Company) | Al-Anezi, Khalaf K. (Kuwait Oil Company) | Latif, Ahmad Abdel (Kuwait Oil Company) | Al-Saqran, Fawaz Salem (Halliburton Energy Services Group) | Vasquez, Rafael B. | Thakuria, Abhijit
The Complex pore geometry of carbonate rocks pose challenges in the formation evaluation, production planning and reservoir simulation. Various diagenetic processes, including solution activities causes lateral and vertical heterogeneities in the formation. There exist two main pore networks in the carbonates which controls the petrophysical and productive characteristics, such as, the interparticle pore network (mainly matrix porosity) and secondary pore network (comprising of vuggy pores as well as fractures). The Minagish Oolite reservoir under this current study is no different and hence warrants a clear understanding of the heterogeneity in the reservoir in order to plan a better completion strategy.
In view of this, a study was carried out in one of the wells integrating conventional well log data, Images logs, NMR logs, Sonic logs, Pressure tests and Core to decide right interval to perforate out of the available zones of interests. Conventional logs are unable to address the geological complexity posed by the reservoir. The different textural elements coexisting in the reservoir (the different pore sizes and their distribution) is identified and captured from image logs and NMR. Integration of NMR and borehole image data allowed us to partition the porosity according to pore sizes and compute continuous permeability which was then calibrated to the mobility obtained from Wireline formation testers, core permeability. This permeability measurement was also supplemented with permeability computed from Stoneley wave energy. NMR results also indicated presence of minor bitumen/very heavy hydrocarbon in certain zones which is further validated with visual observation of cores under UV light. Later the permeability results were calibrated with Core permeability and helped to conclude on the presence of heavier hydrocarbons. The integrated analysis allowed us to identify the best flow units over the entire interval and there by optimizing the completion strategy.
The Minagish Field in Kuwait was discovered in 1959 and is located in the southwestern part of Kuwait. It contains several reservoir intervals in its stratigraphic column varying from early Jurassic to late Cretaceous. The Minagish Formation belongs to the lower part of the Thamama Group. The Minagish Formation is a carbonate succession that is classically decomposed in three formation members: Upper, Middle and Lower Minagish. Their depositional setting is under a transgressive system tract regime in a proximal to distal outer ramp to basinal setting and comprises wackestone, packestone and argillaceous rich mudstone with shale interbeds (Davies et.al., 2000). The current study focuses on the Middle Minagish member which mainly is comprised of wackestone, packestone with rare mudstone deposited in a proximal to distal outer ramp environment. The equivalent of this member in the onshore is represented by oolitic grainstone facies having excellent porosity and permeability. The Minagish Oolite occurs in the middle member of the Minagish formation and is the main producing unit. Intense micritization has generated high proportions of microporosity, and it is the distribution of these micropores which mostly influences permeability and hence creating heterogeneity in this carbonate.
Advanced smart multilateral wells with extended reservoir contact from a single well location have accelerated sustained oil production and increases hydrocarbon recovery from ultra-high water mobility oil-wet Burgan reservoir in Minagish Field West Kuwait. Further the smart multilateral wells have proven to be a great tool for adequate proactive reservoir management and production management without well interventions. The Burgan reservoir has active aquifer, very high permeability sands associated with active faults and contain highly viscous reservoir fluid with downhole viscosity of more than 40cp, enhance water mobility and resulted in premature water breakthrough with increasing water cut trend within few months of production in existing horizontal wells. This has resulted into non-uniform reservoir depletion, by-passed oil regions and low oil recovery.
The smart level-4 multilateral wells were successfully designed and implemented in Burgan reservoir by combining the reliable Level-4 junction along with stacked dual lateral completion having customized viscosity independent Inflow Control Device (ICD), customized two Inflow-Control Valves as well as down hole gauges, wide operating range Electrical Submersible Pump (ESP), suitable wellheads, X-MAS tree and Integrated surface panel for real time data monitoring first time in Kuwait. The improved production performance of smart multilateral wells in Burgan reservoir of Minagish Field, West Kuwait have achieved appropriate production management through flow regulations across laterals and adequate reservoir management with the combination of inflow control device as well as inflow control valves along with downhole pressure temperature gauges. Moreover the smart multilateral wells have enhanced sustained oil production, maximizes hydrocarbon recovery at lowered capital and operational expenditure resulted in improved economic performance of reservoir with significant increase in net present value (NPV). The paper covers the successful implementation of smart multilateral wells and its effectiveness in achieving the life-cycle production management as well as proactive reservoir management supported with actual well performance results. Further the paper details about the economic benefits of smart multilateral wells and its contribution in improving the economic performance of Burgan reservoir of Minagish Field, West Kuwait.