Carbonate heterogeneity exists in different scales and affects different petrophysical estimations. Heterogeneity must be considered for effective core-log integration in order to ensure both core and logs measure rock volumes large enough to sample all rock properties. The conventional integration method is to compare data from the analysis of 1 in. or 1.5 in. diameter plugs (1.5 in. in length) or whole core samples, and compare the results with the same properties derived from logs. Because of heterogeneity, the results do not always compare well unless the rock volumes measured by both core and logs embody the variations and heterogeneity of the rock properties.
Validation of petrophysical models through core-log integration requires an understanding of the scale of reservoir heterogeneity. This paper develops a workflow from a case study evaluating the effects of porosity and mineralogical heterogeneity on core-log integration. Log and core data were available from carbonate intervals in three wells. In each well, porosity and mineralogy were determined from open hole density, neutron, and elemental capture spectroscopy (ECS) logs. The log values were compared to porosity, X-ray diffraction (XRD), and X-ray fluorescence (XRF) data from 86 core plugs (1 foot spacing) and XRD and XRF data from 656 ft of homogenized core slabs. In addition, a special signal processing technique, including homomorphic filtering, reversing intensity values and automatic thresholding, was developed to estimate anhydrite volume percentage from core plug and core slab photographs.
The degree of mineralogical heterogeneity was quantified with spatial variograms. In the case study, the petrophysical evaluation of carbonates was optimized after determining that, among the open hole logs and capture spectroscopy logs, the heterogeneity lengths of neutron porosity and density are similar, and also similar to that of calcite and dolomite. Although, the anhydrite mineralogy is very complex and heterogeneity exists in all scales.
Heterogeneity length was used to identify zones where core mineralogy from core plugs was sufficient for core-log integration and zones where mineralogy from core slabs was required. Heterogeneity is affected by the bed thickness and size and abundance of nodules, and the decision to use core plug or slab data must satisfy the parameter with the most complex heterogeneity. If heterogeneity length is less than 8 in., core plugs can be used. If the heterogeneity length is larger than 8 in., homogenized core slabs are required.
In the case study, the accuracy of the petrophysical models was improved using the scale of heterogeneity to select the proper type of core sample. In addition, this heterogeneity quantification methodology has the potential to improve the selection of samples for lab measurement of permeability, density, etc.
In summary, the workflow provides a robust method to quantify heterogeneity to improve petrophysical evaluation through effective core-log integration.
To drill deepening hole below 7" liner through deep section of compact interbedded carbonate formation results slow rate of penetration (ROP). Beside the limberness of BHA configuration (which is stiffer for the larger sizes of BHA) thus generates various string vibrations, the used of heavier mud weight can also effect overbalance pressure thus reduces drilling ROP.
This paper outlines the two stages diameter PDC bit, that proficiently increases drilling efficiency in order to produce faster ROP through small hole, deep section drilling. When the PDC bits cutting structure is separated into two stages of hole diameters, the mechanical energy that is required to destroy a given volume of the rock to drill can be significantly reduced. This energy reduction can be equivalent to the percentage of the hole size reduction relative to the final hole diameter. The reduced hole diameter that is described as pilot hole will be drilled by the first stage of the bit. The second stage of the bit that is called as reamer section simply enlarges a stress relieved pilot hole, to a final hole diameter.
The Mechanical Specific Energy (MSE) concept that is defined as work that is required to fail a given volume of rock has been formulated proportionally with formation rock strength. MSE can also be defined as input energy to result ROP. The ROP to drill a smaller hole is faster than ROP to drill larger hole although with similar BHA, whilst ROP to enlarge a pilot hole always faster than ROP to drill the pilot hole.
Because the bi-center bit has a pilot section that can be used for drilling a smaller pilot hole and a reamer section for enlarging pilot hole to a final hole size, therefore it shoud be able to produce faster ROP compared to conventional one stage PDC bit. The field results revealed that all of 5-3/4" x 6-1/2" and 6" x 7" bi-center bits that were run below 7" casing by Kuwait Oil Company in Kuwait - through deep wells, have drilled the intervals more than 30% faster than conventional PDC bit.
Kuwait Oil Company Deep Well Division have drilled several deepening hole below the 7?? liner in order to produce hydrocarbon from the lower intervals of the existing production wells through several fields that were explored in 1950's decade. These deepening well drilling campaigns have been actively performed through the oil field located on the northern area of Kuwait that is shown on map, Figure-1.
Drilled-cuttings circulated by drill-mud through the wellbore, while drilling is in progress, can be a clue to many inimical circumstances such as the ' mechanical sticking of the drill-string', 'presence of abnormal pressure zone or gas bearing zone' etc. If the cuttings are accumulated around the BHA, in the section of hole being drilled, owing to the contexts, such as, ‘insufficient mud annular velocity', 'improper composition of the mud' or 'increased penetration rate', it leads to 'drill-string stuck-up' which can cost a substantial amount of money. This paper proposes a novel technique, which can generate and transmit the real-time images of wellbore around the BHA, thus, enabling real time monitoring of the flow path of freshly drilled cuttings, being flushed and circulated out by drill-mud. Real-time images of ‘the area around BHA', facilitates live monitoring of well cuttings, thus, provide a valuable information regarding cuttings that are being accumulated around the BHA. The produced thermal images of ‘generated cuttings' can provide valuable input for the selection of certain drilling parameters, such as, type of bit to be used, 'equivalent circulation density & viscosity of mud' to be maintained etc., thus, enhancing the efficiency of drilling-mud circulation system.
Theory and practice in the past on well testing reservoir with multi-phase flow such as oil and water system achieved limited success. Methods include multi-phase pseudo-pressure, pressure squared and total compressibility, total mobility, i.e. Perrine-Martin (P-M) method. As recognized by the industry, multi-phase pseudo-pressure approach was flawed, while only P-M method is applicable in strictly oil-water system.
Multi-phase flow well testing research subject attracted the oil industry's interest again is purely due to the onset of permanent down hole gauge (PDG), which made long term multi-phase flow transient pressure data at every stage available.
This paper explored in depth the problem of well testing in oil-water two-phase flowing system further. Four types of flow mechanisms were modeled and studies were conducted through numerical well testing. These are: (1) dispersed flow with uniform saturation; (2) dispersed flow with non-uniform saturation; (3) oil-water segregated flow and (4) oil reservoir with aquifer-support. Case (1) is an ideal case, where oil and water assumed to be fully dispersed across the entire reservoir thickness. But in practice, water saturation is non-uniform in reservoir, so it is in fact the case (2). Case (3), segregated flow occurs when gravity forces are dominating, leading to complete segregation of oil overlying water. Such situation can also be due to early water breakthrough in layered reservoir with high permeability formation. Case (4) characterizes the situation where the well is completed in part of the formation away from the water formation in order to prevent water coning. This will create a different flow problem due to spherical flow.
Transient data were generated through numerical experiments for every defined flow mechanisms above. Considering relative permeability curves, traditional P-M method was fully examined and modified to obtain the true reservoir properties such as absolute permeability in these situations. Following the numerical well testing procedures, interpretation issues due to the difference between the theory and practice were addressed much more properly and clear.
Well testing have been used for many years in the oil industry, to evaluate well conditions and obtain reservoir parameters such as permeability, skin factor, average pressure and well productivity. With the advent of PDG available to the industry, continuous reservoir monitoring and dynamic reservoir management in mature field becomes possible. As a lot of oil field reached middle to high water-cut stage, the influence of multiphase flow due to long-term nature of PDG data is significant.
Traditionally, well test interpretation approach is under the conditions of single phase and uniform reservoir. Well testing in multiphase flow reservoir is difficult due to the well test equations describing multiphase flow are highly non-linear. In order to get simple analytical solutions and use single phase theory to analyze the data from multiphase flow reservoir, many assumptions have to be made. In the literature, many articles on this subject were published. In summary, these publications can be divided into three main categories. The first is the pressure approach (P-M approach, Perrine, 1956; Martin, 1959), the second is the pseudo-pressure approach (Fetkovich, 1973; Raghavan, 1976), and the third is the pressure-squared approach (Khalifah, 1987).
In the gas plants, gas condensate often contains unwanted glycol, water and salt together with light HC, H2S, mercaptanes which are soluble in condensate and cause corrosion, fouling, plugging, scaling, catalyst poisoning and other detrimental effect on plant operation. Condensate stabilizing is a process that mainly uses for separation of mentioned components from raw gas condensate in order to meet product specifications which is on-spec RVP, water and salt contents for the ultimate product.
At the overall view point, condensate stabilizing process consist of four main parts which are; separation of free aqueous phase and light HC from heavy HC in a high pressure three phase separator, desalting and sludge removal using desalter, separation of remained light HC by a medium pressure distillation tower and finally degassing of column stabilized product plus with debutanizer bottom product (C5+) in a low pressure flash drum in order to produce final product for sending to atmospheric storage tanks.
As a real case in our gas plant, due to low performance of stabilizer reboiler, efficiency of process was reduced gradually and caused off-spec product to be produced. So, other operational parameters affect on process efficiency was changed and optimized in order to compensate product specification and meet on-spec values. The most operational parameters which affect product specifications are as below:
1. Changing demulsifier and water wash injection to desalter mean while draining of interface layer of desalter once per each operating shift.
2. Optimization differential pressure of the desalter mixing valve.
3. Effect of stabilizing column pressure reduction to the optimum value, in a way that does not affect proper working of off-gas compressor.
4. Effect of increasing stabilizer column condenser temperature.
5. Effect of increasing temperature of inlet feed to stabilizer column.
6. Effect of (C5+) flow rate and RVP on the condensate RVP.
This paper introduces main results of the actual case studies in plant together with simulation results. Comparison between actual and simulation results indicate excellent satisfaction from practical engineering standpoint and high reliability of test run.
Introduction to South Pars Gas Field
The SOUTH PARS gas field is in Iran and is the North Eastern side of a large structure located in the Persian Gulf, known in Qatar as the North Field. The field is located offshore around 100 km south of Assaluyeh. The onshore receiving facilities and gas treatment plant are located on the Iranian coast of the Persian Gulf near Assaluyeh village.
Hydrocarbons are found in several intervals, which the most important reservoir is the Khuff carbonated, around 3000 meters below ground, with a thickness of approximately 450 meters. The field is the largest gas field in the world.
28 phases was predicted for development of this gas field in Iran side. Each gas phases was designed for processing of 1000 MMSCFD of raw gas plus with 40000 BPD condensate, including offshore production platforms, under sea pipe lines and onshore processing facilities. The reservoir fluid mixed with MEG in order to avoid risk of hydrate formation in the presence of free and saturated water.
Islam, Md. Aminul (NTNU) | Skalle, Pal (Norwegian University of Science and Technology) | Faruk, A.M.M Omar (Norwegian University of Science and Technology) | Pierre, Benjamin (Norwegian University of Science and Technology)
Time delayed mechanical borehole stability is mostly depending on the pore pressure consolidation process. Establishment of pore pressure equilibrium in shale is a time dependent process which is characterized by shale intrinsic properties i.e., porosity, permeability, fluid and rock stiffness parameter etc. In shale, water movement is greatly restricted by the low permeability of shale which may cause pore pressure storage. The Influence of induced pore water pressure and its dissipation is critical for the evaluating of time delayed borehole stability.
This paper discusses and presents a sensitivity analysis of the impact of shale intrinsic properties on transient pore pressure and its impact on time delayed mechanical borehole instability. The aims are to establish pore pressure trend, material plasticity, and time delayed borehole collapse risk. In an attempt to minimize transient pore pressure related instability problems, detailed and careful analyses are highly dependent on the constitutive models adopted for the shale. In this study, a physical model was used to introduce hypotheses of time delayed stability and both analytical and numerical models were developed to verify the hypotheses. The analytical model is based on poroelastic constitutive model, coupled with pressure diffusivity formulation. A numerical material model is developed based on finite elements. The analytical model quantifies shale intrinsic properties vs time delayed stability; whereas, the numerical model diagnoses pore pressure storage effect during underbalanced drilling in shale and its impact on mechanical instability. The undrained condition (immediately after the wellbore is drilled) as well as the drained condition was analyzed. The integrated approach in this study may give a clear picture on shale complexicity and its adverse effect on time delayed stability. Wellbore stability models that include some aspects of coupled have already been developed. However, time delayed borehole instability in shales in UBD condition is a new research area; adjustments are required in existing model.
The analytical simulation results show that shale permeability higher than 40 hD, the difference of the consolidation time for different finite characteristic time are insignificant and converge to zero while permeability 100 hD. In addition to shale permeability, other parameters (i.e. pore fluid viscosity, porosity and fluid bulk modulus) are influencing the consolidation processes. This paper demonstrates the effects of such parameters also. The numerical results implies that a M-C elastic - plastic model is capable of evaluating plasticity and material deformation effects in UBD conditions along with accounted time delayed transient pressure trend in shale. It was shown that the shale behaviour during UBD is a transient problem, and can not be described without a fluid diffusion process. It is also noted that shale intrinsic parameters are playing a significant role in time delayed borehole stability analysis.
KEYWORDS: shale, consolidation, transient pore pressure, finite element method, time delayed instability.
Kuwait is keen in developing the shallow Miocene Heavy Oil resources of Ratqa Lower Fars. EOR screening studies indicate thermal methods of Cyclic Steam Stimulation (CSS) and Steamflood as most promising technologies for developing this resource and meeting KOC goals. Thermal development was tried earlier in this field. In 1980's two CSS pilots were carried out that are considered successful. Steam Flood was also planned at that time but the project got stalled due to the Gulf War. Facilities got destroyed during that war. The present paper describes how thermal simulation techniques were used to design a new and improved thermal pilot, by matching the old CSS pilot performance, learning from history matching process and carrying out multiple prediction scenario analysis.
The pilot plan is currently at the early phase of implementation in this field and is considered very important risk mitigation step, towards commercialization of the project. The paper summarized the objectives of the pilot, so that a firm understanding is generated of the expectations and relevance of the pilot in the larger development scheme of the project.
Thermal simulation study results for arriving at the pilot plan would be presented in the paper. How history matching of old CSS pilots and the cold flow data obtained from recent CHOPS pilot wells help in arriving at an improved design of the Steam Flood pilot would be documented.
The contents of the paper can help generating ideas in designing pilots in similar Heavy Oil fields. The document can also serve as a score card for the Lower Fars thermal pilot post implementation, to understand the original objectives of the pilot.
Condensate banking is a much studied phenomenon in gas condensate reservoirs. An excessive drop in flow rate occurs when the bottom hole flowing pressure of a producing well falls below the dew-point pressure. Condensate dropped around the well bore increasingly reduces relative permeability to gas until a critical liquid saturation is reached. As liquid saturation increases above the critical value, two phase flow of both liquid and gas creates the equilibrium necessary to maintain the reduced, but steady state flow. The reduced gas permeability is described as a positive skin reducing the well rate PI used in the forecasts. In more severe cases, the PI may be reduced to cause sub-commercial rates. Even though several equations are available in the literature to estimate skin damage due to condensate banking, it is well recognized that localized reservoir characteristics, especially in naturally fractured carbonates must be applied to obtain an accurate value.
In this paper, numerical inverstigations of the impact of condensate banking on well productivity in the North Kuwait Jurassic Complex (NKJC) gas-codensate reservoirs are performed. A representative reservoir from Sabriyah field in the Najmah Sargelu formation was selected for the purpose. A general equation thus developed for rich condensate gas in naturally fractured carbonates was applied to the complex of reservoirs existing in the NKJC to study the impact condensate banking of full field performance.
North Kuwait Jurassic is a challenging exploration and development environment that consists of highly complex compartments and heterogeneous reservoirs where natural fractures contribute significantly to the well productivity. Parts of the Jurassic reservoirs consist of very tight matrix with a high density of connected fractures while in other areas fractures are sparse and have limited connectivity. Compositions vary across the complex. Fluid samples from some reservoirs exhibit a dew point pressure behavior (near-critical gas-condensate) while other reservoirs exhibit a bubble point pressure behavior (near-critical volatile oil)
(Ghorayeb et al., 2008, 2009).
The formation of the condensate in gas codensate reservoirs reduces the liquids content of produced gas. The liquids thus dropped cannot be recovered due to critical saturation limits. The phenomenon therefore, results in a reduction in a loss of oil recovery factor. But, the near well choking or the so called condensate blockage while the overall reservoir pressure is still higher than the dew point will restrict the gas flow hence reducing the producitivity of the well. If the condensate banking behaviors are not understood at the beginning of the development, production performance can be overestimated. This might potentially be a serious
problem, since well deliverability of gas codensate reservoirs is critical to meet the long term gas targets in the NKJC.
This paper reviews the behavior of condensate formation near the wellbore that results in condensate blockage. We constructed a conceptual single well simulation model with logarithmic grid to investigate grid effect on condensate banking. The investigation aims at selecting an approach to adjust a coarse grid model to match the results of the fine grid model. Different available approaches were used for the purpose namely: 1) productivity index multiplier, 2) skin factor, 3) velocity dependant flow and 4) generalized pseudo pressure.
Al-zain, Ahmed K. (Saudi Aramco) | Said, Rifat (Saudi Aramco) | Al-Gamber, Salman Dawood (Saudi Aramco) | Al-Driweesh, Saad M. (Saudi Aramco) | Al Shahrani, Khzam (Schlumberger) | Jacobsen, Jan Rune Gro (Schlumberger)
Since the advent of horizontal technology, new wells have been drilled with thousands of feet of horizontal section to expose large reservoir areas. The advancement of drilling technology also allows drilling more complex wells, such as multilaterals for maximum reservoir contact (MRC). These complex wells impose great challenges with respect to well accessibility for rigless well interventions. One of the initial well interventions, which follow drilling completion, is acid stimulation to remove formation damage.
On the other hand, the recent advancement of coiled tubing (CT) enables rigless interventions of complex wells while acquiring real time downhole measurements. The fiber optic enabled coiled tubing (FOCT) provides combined services of data acquiring and running other CT tools required for well treatments. The fiber optic telemetry system consists of a pump-through bottom-hole assembly (BHA) with a casing collar locator (CCL), pressure and temperature sensors, optical fibers inside CT, and a surface readout unit. By the virtue of the optical fiber, distributed measurements are also viable options to obtain temperature profiles. The temperature surveys allow evaluating flow distribution through temperature responses, thereby optimizing acid stimulation.
A multilateral tool (MLT) using an indexing flow activated bent sub allows locating and accessing the laterals and stimulating them. The CCL readings via the FOCT provide a real time confirmation of accessing laterals.
This paper highlights the first worldwide CT application of combining the fiber optic telemetry system for acquiring downhole data on real time, and a multilateral tool for accessing and stimulating a trilateral oil producer in a major carbonate reservoir in Saudi Arabia. This combination has resulted in a successful optimized acid stimulation of all three laterals. This paper also discusses in detail the job execution challenges, lessons learned, and experience gained to optimize similar future jobs.
We report an experimental study of CO2 and N2 foam flows in natural sandstone cores containing oil with the aid of X-ray Computed Tomography. The study is relevant for Enhanced Oil Recovery (EOR). The cores were partially saturated with oil and brine (half top) and brine only (half bottom) to mimic the water-oil transition occurring in oil reservoirs. The CO2 was used either under sub- or under super-critical (immiscible and miscible) conditions, whereas N2 remained subcritical. Prior to gas injection the cores were flooded with several pore volumes of water. In each experiment water flooding was followed by the injection of 1-2 pore volumes of a surfactant solution with Alpha Olefin Sulfonate (AOS) as the foaming agent. We visually show how foam propagates in a porous medium containing oil.
At low-pressure experiments (P=1 bar) in the case of N2, weak foam could be formed in the oil-saturated part. Diffused oil bank is formed ahead of the foam front, which results in additional oil recovery, compared to pure gas injection. CO2 hardly foams in the oil-bearing part of the core, most likely due to its higher solubility. Above critical point (P=90 bar), CO2 injection following the slug of surfactant reduces its mobility in absence oil. Nevertheless, when the foam front meets the oil it becomes highly diffuse. The presence of the surfactant (when foaming super-critical CO2) hardly improves oil recovery and or modifies the pressure drop profile, indicating the detrimental effect of oil on foam stability in the medium in this specific case. However, at miscible conditions, injection of surfactant prior to CO2 injection significantly increases the oil recovery.
A problem associated with many secondary and tertiary gas (e.g., CO2, N2, steam, air, etc.) injection projects is the inefficient gas utilization and poor sweep efficiency due to viscous fingering and gravity segregation. This leads to much lower recoveries than can potentially be expected from such methods. The fingering and segregation result from high gas mobility (displacing phase) compared to oil and water (displaced phase); i.e., gas density and viscosity are much lower than those of oil and water. Unfavorable mobility ratios lead to even more severe channeling in heterogeneous reservoirs. Consequently, the drive fluid does not contact a large part of the reservoir and the volumetric sweep efficiency of the reservoir remains poor .
The alternation of slugs of water and gas, i.e., Water Alternating Gas (WAG), has been common practice to obtain better mobility ratios and improve sweep efficiency [2-4]. Nonetheless, WAG can eventually suffer from viscous instabilities and gravity segregation and, therefore, has not always been a successful method of controlling the gas mobility . The addition of surfactant to water results in a process called Surfactant Alternating Gas (SAG). By foaming the gas and, thus, reducing its mobility, especially in the swept or high permeability parts of the reservoir, one can potentially overcome the problems encountered in WAG [e.g. 6-12].