Sanyal, Tirtharenu (Kuwait Oil Company) | Al-Hamad, Khairyah (KOC) | Jain, Anil Kumar (KOC) | Al-Haddad, Ali Abbas (KISR) | Kholosy, Sohib (KISR) | Ali, Mohammad A.J. (Kuwait Inst. Scientific Rsch.) | Abu Sennah, Heba Farag (Kuwait Oil Company)
Improved oil recovery for heavy oil reservoirs is becoming a new research study for Kuwaiti reservoirs. There are two mechanisms for improved oil recovery by thermal methods. The first method is to heat the oil to higher temperatures, and thereby, decrease its viscosity for improved mobility. The second mechanism is similar to water flooding, in which oil is displaced to the production wells. While more steam is needed for this method than for the cyclic method, it is typically more effective at recovering a larger portion of the oil.
Steam injection heats up the oil and reduce its viscosity for better mobility and higher sweep efficiency. During this process, the velocity of the moving oil increases with lower viscosity oil; and thus, the heated zone around the injection well will have high velocity. The increase of velocity in an unconsolidated formation is usually accompanied with sand movement in the reservoir creating a potential problem.
The objective of this study was to understand the effect of flowrate and viscosity on sand production in heavy oil reservoir that is subjected for thermal recovery process. The results would be useful for designing completion under steam injection where the viscosity of the oil is expected to change due to thermal operations.
A total of 21 representative core samples were selected from different wells in Kuwait. A reservoir condition core flooding system was used to flow oil into the core plugs and to examine sand production. Initially, the baseline liquid permeability was measured with low viscosity oil and low flowrate. Then, the flowrate was increased gradually and monitored to establish the value for sand movement for each plug sample. At the end of the test, the produced oil containing sand was filtered for sand content.
The result showed that sand production increased with higher viscosity oil and high flowrate. However, sand compaction at the injection face of the cores was more significant than sand production. In addition, high confining pressure contributes to additional sand production. The average critical velocity was estimated ranged from 18 to 257 ft/day for the 0.74 cp oil, 2 to 121 ft/day for the 16 cp oil, and 1 to 26 ft/day for the 684 cp oil.
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.
Mishra, Prasanta Kumar (Kuwait Oil Company) | Al-Harthy, Abdulrahman (Target Oilfields Services) | Al-Kanderi, Jasem M. (Kuwait Oil Company) | Al-Raisi, Muatasam (Target Oilfields Services) | Al-Alawi, Ghaliah (Target Oilfields Services) | Alhashmi, Salim (Target Oilfields Services) | Turkey, Shaikha (Kuwait Oil Company)
This paper presents the main steps of rock-typing workflow and the technique applied to estimate permeability.
Reservoir rock typing (RRT) is a process of up-scaling detailed geological and petrophysical information to provide more accurate input for 3D geological and flow simulation models. The reservoir rocks that correspond to a particular rock type should have similar rock fabric, pore types and pore throat size distribution. The study integrated multi-scale data types to develop a robust and predictable rock type scheme. This consists of detailed sedimentological description of depositional environment and associated sedimentary features, detailed numerical petrographic analysis of rock texture, grain types, porosity types and rock mineralogy and petrophysical data grouping using openhole log and core plugs porosity-permeability relationship and pore throat size distribution (MICP).
The main objective was to develop a reliable reservoir rock type scheme that captures the heterogeneity in Jurassic carbonate reservoir for the Middle Marrat Formation in South East Kuwait area and implementation of the RRT to the permeability prediction within the field. Integration of the thin sections, porosity-permeability, pore throat size and distribution has resulted in the identification of reservoir rock types. A total of 14 different rock types were identified within the reservoir interval in the cored wells, which is subsequently grouped into eight due to modelling limitation. The RRT up-scaling was done in a way to minimize the impact of grouping on permeability and saturation computations. The prediction success between the cored RRT and the predicted RRT using openhole data is more than 85%. As a result, the permeability computation success between core plugs and computed permeability using the RRT is more than 80%.
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.
During recent years there has been a significant increase in the use of filter cake removal systems that involve in-situ release of formic or lactic acid during the clean-up stages of the reservoir section, particularly in limestone formations. Furthermore, there have been opportunities to compare the field performance of these relatively small applications of weak, organic acids with significantly larger application volumes of highly concentrated hydrochloric acid (HCl). Surprisingly, some results showed that the smaller volumes of the weaker, organic acids could have equivalent or better performance than that produced by the more traditional HCl-based treatments. In particular this relationship was also observed in cases where the volume of HCl applied had significantly greater power to dissolve limestone than was the case for treatment with the more successful organic acid.
It is well known that productivity of wells in carbonate reservoirs is usually greatly improved by treatments designed to remove the filter cake and the low-permeability zone created by the drilling process, but it is not obvious why smaller volumes per foot of weak organic acid should be more effective than larger volumes per foot of stronger and more concentrated mineral acid.
It has been observed that the acid precursors which release the in-situ acids are applied to the formation in a neutral condition. The paper discusses the implications of using neutral acid precursors, and laboratory data is presented showing the effects of such treatments on the near-wellbore matrix permeability.
Hruška, Marina (Chevron Energy Technology Company) | Bachtel, Steven (Chevron Energy Technology Company) | Archuleta, Bonny (Chevron Energy Technology Company) | Skalinski, Mark (Chevron Energy Technology Company)
In this integrated study using resistivity images, conventional openhole logs, and core data from a Middle Eastern reservoir, abundance and geometric configuration of bedded and nodular evaporite have been studied to help distinguish which nodular forms of evaporite may be related to a permeability suppression. Several logs have been calculated from the resistivity image log to quantify nodular evaporite and help predict the presence of corresponding core facies well. Compared with thin-section description, most samples of nodular evaporite were exhibiting fine-scale cementation as well, and their permeability was suppressed compared with samples with rare or no fine-scale cementation in thin sections.
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.
The initialization of a reservoir simulator calls for the populating of a three-dimensional dynamic grid-cell model using subsurface data and interrelational algorithms that have been synthesized to be fit for purpose. These prerequisites are rarely fully satisfied in practice. This paper sets out to strengthen initialization through four key thrusts. The first addresses representative data acquisition, which includes the key-well concept as a framework for the cost-effective incorporation of free-fluid porosity and permeability within an initialization database. The second concerns the preparation of these data and their products for populating the static and dynamic models. Important elements are dynamically-conditioned net-reservoir cut-offs, recognition of primary flow units, and establishing interpretative algorithms at the simulator grid-cell scale for application over net-reservoir zones. The third thrust is directed at the internal consistency of capillary character, relative permeability properties and petrophysically-derived hydrocarbon saturations over net reservoir. This exercise is central to the simulation function and it is an integral component of hydraulic data partitioning. The fourth concerns the handling of formation heterogeneity and anisotropy, especially from the standpoint of directional parametric averaging and interpretative algorithms. These matters have been synthesized into a workflow for optimizing the initialization of reservoir simulators. In so doing, a further important consideration is the selection of the appropriate procedures that are available within and specific to different software packages.
The implementation of these thrusts has demonstrably enhanced the authentication of reservoir simulators through more readily attainable history matches with less required tuning. This outcome is attributed to a more systematic initialization process with a lower risk of artefacts. Of course, these benefits feed through to more assured estimates of ultimate recovery and thence hydrocarbon reserves.
The excess of water production from oil wells in several areas of Khafji field is a subject of concern for reservoir management. Water shut-off techniques are common practices to reduce water production which is resulted in well productivity improvement. An oil producer well-A, was worked-over on February 22, 2006 to conduct a water shutoff technique on existing perforation intervals utilizing a cement squeeze. Several logs such as RST and Gamma Ray were carried out to identify the fluid movement. Then, the well was produced with an oil rate of 1,200 BOPD and a rapid increase of water cut of 60%. The well was still unstable in terms of rate due to high water cut. The well was considered for rigless work-over to control the water using Mechanical Through Tubing Bridge Plugs (MTTBP) to isolate the lower two perforation sections. After setting the Bridge Plug with 8 ft. of cement above the plug, the well was revived with production stream. During the first 24 hrs of well production, the treatment result was not as expected which resulted in 100% water cut. A discussion was made by reservoir management engineer to continue of production for additional 24 hrs. With time, the well showed a positive result with a reduction in water up to 95%. It is recommended to keep the well to be produced over 21 days with final results showed the well revived with an oil production of 1,500 BOPD with zero water cut.
The result showed a successful water shutoff technique and scenario to retrieve the well with 100% water cut produced after treatment. Challenges, intervals selection, design criteria, lessons learned, and results of the water shutoff technique will be discussed in this paper.
Zhao, Limin (PetroChina Co. Ltd) | Liu, He (Research Inst. Petr. Expl/Dev) | Guo, Rui (China Natl. Petroleum Corp.) | Feng, Mingsheng (China Natl. Petroleum Corp.) | Zhang, Zhaowu (PetroChina Co. Ltd.) | Zhang, Yaowen (CNPC) | Wang, Jun (RIPED, PetroChina)
AD oilfield is located in the southeast of Iraq and structurally it is a long axis gentle anticline in Mesoptamian foredeep. This oilfield is in the development planning stage. The accurate formation evaluation plays an important role in making development strategy. In this paper, integrated evaluations of major target formation, Cretaceous carbonate Khasib II were introduced with the combinations of available data.
Khasib II was mainly deposited within marine carbonate platform shoals and distributed stably in the full field with an average thickness of 40m. Based on the core data, four rock types are defined. Upwards lithology varies from planktonic foram micritc wackestone through green algae packstone to bioclastic and calcarenite grainstone. The porosities are almost same, about 25% while permeability varies in a large range for different lithology. Lower Khasib II planktonic foram limestone has no more than 1mD in permeability and no higher than 1ohm.m in resistivity while Upper Khasib II limestones have 10mD in average permeability and high resistivity. Reservoir spaces are mainly pores and vugs while fractures are not developed. Pore types are mainly intragranular pores, intergranular pores and intercrystal pores. Two throat types, the tubular throat and the lamellar throat are identified which are the major control factors for leading to the difference of permeability in lower and upper Khasib II. Test results show that lower planktonic foram limestone is dry and upper limestones produce oil which can be inferred that the low resistivity for lower Khasib II is resulted from the lithology rather than water. Reservoir distribution, petrophysical properties and fluid distribution for upper Khasib II are analyzed.