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.
Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation.
This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm.
A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation.
Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations.
The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWiseSM ED-XRF instrument at wellsite.
Telang, Milan (Kuwait Oil Company) | Al-Matrook, Mohammad F. (Kuwait Institute for Scientific Research) | Oskui, Gh. Reza (Kuwait Institute for Scientific Research) | Mali, Prasanna (Kuwait Oil Company) | Al-Jasmi, Ahmad (Kuwait Oil Company) | Rashed, Abeer M. (Kuwait Institute for Scientific Research) | Ghloum, Ebtisam Folad (Kuwait Institute for Scientific Research)
Asphaltene deposition problems in Kuwait have become a serious issue in a number of reservoirs during primary production in different fields, resulting in a severe detrimental effect on the economics of oil recovery. Hence, one of the mitigation approaches in the field is using remedial solvent treatments, such as Xylene or Toluene, which is very costly and harmful to the environment.
Kuwait Oil Company (KOC) is planning to produce from asphaltinic Marrat wells that have been shut down due to low bottom-hole pressure (BHP), by artificial lifting technique using an Electric Submersible Pump (ESP) supported with continuous chemical injection, as a pilot. The main objective of this study was to investigate in the lab the effectiveness of various concentrations of toluene/diesel (T/D) mixtures on Marrat reservoir fluid in order to mitigate asphaltene deposition problem during the actual pilot implementation.
Preliminary screening tests were conducted on the surface oil sample using Solid Detection System (SDS) "laser technique?? to determine the optimum dose of the T/D mixture ratio. The results showed that pure diesel accelerated the asphaltene precipitation; however, mixing T/D inhibited the precipitation process. Series of pressure depletion tests was then conducted on live oil , single phase samples, to determine the Asphaltene Onset Pressure (AOP) with and without adding various ration of T/D solvents at different temperatures from reservoir to surface conditions.
The results revealed that using 15% (by volume of oil) from the (50T:50D) mixture reduced the AOP close to the bubble point pressure. Furthermore, the amount of the precipitated asphaltene was physically quantified using a bulk filtration technique. It was observed that, based on blank sample, the wt% of the precipitated asphaltene was minimized at the AOP and maximized at the bubble point. However, using the recommended mixture of 50T/50D, the amount of asphaltene that precipitated was almost negligible. Therefore, from a health, safety, and economic point of view, this study recommends using a low dose of 7.5% (by volume of oil) from toluene mixture with diesel (50%:50%) rather than using pure toluene to prevent the precipitation.
Acharya, Mihir Narayan (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Al-Ajmi, Saad Abdulrahman Hassan (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger)
The deep, sub-salt reservoir complex is tiered with fractured tight carbonate at bottom and top, with the two sub-units of "upper unconventional kerogen?? and "lower inter-bedded kerogen-carbonate?? in the middle. This depositional setting is challenging for horizontal well placement where the thicknesses of respective sub-units are about 50 and 30 feet with varying geomechanical and petrophysical properties. Additionally, this complexity poses limitations in completions and effective stimulation of the Kimmeridgian-Oxfordian reservoirs in several gas fields at development stage in Kuwait.
A horizontal well is placed in the lower sub-unit of the laminated complex of unconventional kerogen and fractured carbonate reservoir as a Maximum Reservoir Contact (MRC) type well. A pilot mother-bore was drilled and logged to identify the lithological properties across the entire vertical domain - facilitates the optimization of horizontal drain-hole placement within the targeted reservoir units.
No wellbore stability issues in drilling were predicted based on the geomechanical understanding where core-calibrated logs from offset vertical wells were considered. However, this modeling method did not have the functionality to integrate the impact of drawdown on the laminated formation which became unstable and collapsed during the short open-hole drill-stem test (DST) plugging the tubing prior to the final completions. An alternative "book-shelf?? geomechanical model was considered at pre-drill stage for predicting the wellbore stability. Once the drilling was completed, the time-lapsed multi-arm caliper indicated the validity of the alternative methodology in predicting the unstable stack of laminations in kerogen-rich strata.
The paper discusses an optimization methodology to enhance the understanding of static and dynamic geomechanical stability through the use of BHI data. Objective of the proposed method is to help improve the effectiveness of completions where wellbore stability due to geomechanical complexity in stacked-pay reservoirs is a primary wellbore challenge in deploying the completions and executing a subsequent stimulation and testing campaign.
Al- Mai, Noura (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Baddula, Ravi Chandra (Kuwait Oil Company) | AlAwadi, Mishari A. (KOC) | Bloushi, Taha (Kuwait Oil Company) | Aouchar, Najet (Schlumberger) | Hamed-naji, Iyad (Schlumberger) | Metzger, Thomas (Schlumberger)
Currently, Kuwait Oil Company (KOC) is successfully producing from high pressure and high temperature formations. The reservoirs are deep with True Vertical Depth (TVD) approximating 15,000 feet, and pressures and temperatures of 11,000 psi and 275o F respectively. The formations are composed of carbonates both tight and porous. The produced hydrocarbons are of high H2S and CO2 content, up to 10% and 12%, respectively.
The aforementioned sour environment in addition to water cut occurrence during the production phase have led to scale creation. In addition, corrosion, erosion and pitting also occur, requiring well intervention to sustain production. Furthermore, well monitoring is essential and planning for workover and well interventions is becoming unconventional with higher associated risk.
The recent scale removal activities proved to be very challenging with weight loss seen from the coiled tubing (CT) of approximately 7,000 Ib and CT leakage while operating at the hole condition. The CT pressure control equipment failed due to sudden increased in H2S concentration, which was attributed to the chemical reaction between the cleaning fluid (15% HCl) and the well fluids/scale mixture.
This paper explains the well history, objectives of operation, execution history, procedures and causes of these challenges. Hence, lessons learned, observations and knowledge gained by the Kuwait Oil Company (KOC) are evolving, advancing, and being employed at an accelerated rate despite high cost.
In high pressure high temperature (HPHT), deep sour gas condensate and volatile oil fields, in which the wells contains approximately 2 - 8 % H2S and 1 - 2.5% CO2 it is necessary to evaluate the corrosion rates for the downhole completion string. As it is well known that, corrosion leads to several major problems which affect the well integrity and the production sustainability through the production string failures and tubing casing pressure communication.
The purpose of this paper is to illustrate an initial monitoring plan to extend the life of a completion string, reduce the number of well interventions and workovers due to corrosion and scale deposition. This systematic approach will improve the future tubing selection criteria and evaluate the need for CRA material also enhancing the downhole inhibition system with reference to KOC safety regulations from operational and economical prospective.
The conclusions of the above will be based on data collected from 13 wells to investigate the key factors which accelerate the corrosion occurrence and rate. As such, a detailed analysis was constructed by using the baseline corrosion logs and their outputs such as time lapse, pitting, and fluid properties vs. metallurgy.
Deep North Kuwait Reservoirs consist of several fields. Production from these near critical fluids Fields was mainly started in 2008. During the early production phase, the corrosion was not a concern because wells were at their initial stage and LTT. Deep North Kuwait Reservoirs are at depths ranging between (14,000 ft - 16,000 ft) with high pressure ~ 10,000 psi and high temperature ~285 F associated with 2 - 8 % H2S and 1 - 2.5% CO2 for particular wells hyper saline water. In 2009, baseline corrosion logs were acquired for some of the producing wells with two repeated corrosion logs for one particular well which suffers the severest corrosion rate as indicated by "baseline log??. The corrosion monitoring plan (2009 - 2011) was implemented for the entire fields to detect the corrosion impact that may seriously interrupt the hydrocarbon deliverability to the production facility [Fig1]. The corrosion exists in different places such as: pipelines, casing, liners and tubing. This paper only discusses the tubing corrosion which impacts the well integrity and could lead to inter-zonal fluid cross flows through: casing, liner and tubing. One of the primary output of this paper is to establish and evaluate the efficiency of the anticorrosion practices to prevent the unexpected corrosion incidents.