The field X is a brown heavy oil field producing under strong bottom water drive since the mid-1980. Production is from a combination of Amin aeolian and Al Khlata glacial reservoir sediments. At present, the development is focused on drilling horizontal infill wells. One of the biggest challenges is the unfavorable mobility contrast between the heavy oil and water causing early water breakthrough.
The Amin Formation, the primary reservoir, is characterized by a high net to gross ratio and an average porosity of 30 %. However the initial hydrocarbon saturation at the same porosity often varies by 20 % in different parts of the field. Furthermore, core measurements show an order of magnitude scatter in permeability at the same porosity, indicating the presence of different facies. In early studies these variations were attributed mainly to the grain size variations. A later petrographical study found that the abundance of clays and feldspars could also severely reduce permeability, but may retain high porosity.
In the current Study it was found that the rocks have variable radioactivity due to the presence of radioactive Potassium isotope associated with feldspars. A fare correlation was observed between the grain size and the content of feldspars from core. A novel approach to reservoir characterization integrating core and logs was developed leading to a major breakthrough in the reservoir characterization including:
• Enhanced permeability prediction using normalized Gamma Ray (GR) log as 3rd parameter;
• Facies identification using normalized Gamma Ray cut-off;
• Facies based Saturation-Height models.
This work is a good example of advances in reservoir characterization achieved by integrating core and log data. It results in better understanding of reservoir properties distribution, optimization of completions of new wells and improvement of further development scenarios. In particular, abnormally high gross production and high water cut in the north of the field is currently in line with new facies scheme.
Transverse fractures created from horizontal wells are a common choice in tight and shale gas reservoirs. Previous work has shown that proppant pack permeability reduction due to non-Darcy flow in a transverse fracture from a horizontal well causes significant reduction in the fracture performance when the gas formation permeability exceeds 0.5 md. There are other configurations and architectures such as aligning the well trajectory with the fracture, either by drilling horizontal wells in the direction that results in longitudinal fractures or by just sticking with drilling vertical wells. However, when drilling and fracturing costs are considered, productivity is not the only optimization consideration.
The field example illustrates a case when the apparent choice to use transverse fractures from horizontal wells proved to be suboptimal from the productivity perspective, but fundamental considering economics. Parametric studies for permeability ranging from 0.01 to 5 md illustrate the importance of economics in addition to physical performance. For similar reservoir characteristics, the optimum fractured well architecture varies considerably, and therefore an extensive reservoir engineering approach may be necessary beyond the well completions and/or current prejudices and inadequate understanding.
Carbonate formations are very complex in their pore structure and exhibit a wide variety of pore classes. Pore classes such as interparticle porosity, moldic porosity, vuggy porosity, intercrystalline porosity, and microporosity. Understanding the role of pore class on the performance of emulsified acid treatment and characterizing the physics of the flow inside is the objective of our study.
The study was performed using vuggy dolomite cores that represent mainly the vuggy porosity dominated structure, while the homogenous cores represent the intercrystalline pore structure. Core flood runs were conducted on 6 x 1.5 in. cores using emulsified acid formulated at 1 vol% emulsifier and 0.7 acid volume fraction. The objective of this set of experiments is to determine the acid pore volume to breakthrough for each carbonate pore class at different injection rates.
In this paper, a novel approach to interpret the core flood run results using thin section observations, tracer experiments, SEM, and resistivity measurements will be presented. Thin section observations provide means to study the vugs size and their distribution, connectivity, and explain the contribution of the pore class in the acid propagation. Relating the rotating disk experiments of emulsified acid with dolomite to our core flood run results will be also conducted in order.
The acid pore volumes to breakthrough for vuggy porosity dominated rocks were observed to be much lower than that for homogenous carbonates (intercrystalline pore structure). Also, the wormhole dissolution pattern was found to be significantly different in vuggy rocks than that in homogenous ones. Comparison of thin section observations, tracer results and the core flood runs results indicates that the vugs are distributed in a manner that creates a preferential flow path which can cause a rapid acid breakthrough and effective wormholing than those with a uniform pore structure. Rotating disk experiment results, demonstrating that the reaction of emulsified acid with dolomite is much lower than that with calcite, showed that the reaction kinetics played a role in determining the wormhole pattern.
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%.
Oil or gas effective and relative permeabilities can be reduced to a great extent due to the invading liquid phase of the drill-in or completion fluid, contrary to the misconception that formation damage is less of a concern in lower permeability reservoirs (e.g., less than 5 md). Many laboratory, well logging, and formation tester data proved that mud filtrate (both from water- and oil-based muds) can deeply invade the formation enhanced by capillary forces. This will result in reduction of the oil or gas effective permeability, especially if the formation exhibits fluid emulsion blocks and phase trapping. Unfavorable interaction of the filtrate with the reservoir fluids and rock minerals can generate emulsions and precipitates. The same scenario may occur in hydraulically fractured formations.
An integrated multidisciplinary approach is pursued in this study to evaluate formation damage/remediation potential of low permeability reservoirs. The techniques involve different formation evaluation methods including core analysis, well logging, and well testing along with various cleanup scenarios. Furthermore, results from petrographic analysis and laboratory experiments (Micro and Macroscopic scales) are related and correlated with the larger Mesoscopic and Megascopic scales of well logs and well testing, respectively.
Results of these efforts lead to the following technical contributions; a) Delineation of the low permeability heterogeneous reservoirs, e.g. the Leduce carbonates, into their hydraulic units. b) Determination of the undamaged formation absolute and relative permeabilities along with the diameter of filtrate invasion. c) A rule of thumb is to minimize or prevent damage from taking place by selecting a drilling fluid that quickly forms an easily removable mudcake. d) Cleaning up damage due to water filtrate may be accomplished by just flowing the well and can be accelerated using solvents or surfactants. However, once the formation reaches its irreducible water saturation, remediating water saturation below the irreducible value may not significantly improve its permeability.
This paper analyzes reaction and thermal front development in porous reservoirs with reacting flows, such as those encountered in shale oil extraction. A set of dimensionless parameters and a 3D code are developed in order to investigate the important physical and chemical variables of such reservoirs when heated by in situ methods. This contribution builds on a 1D model developed for the precursor study to this work. Theory necessary for this study is presented, namely shale decomposition chemical mechanisms, governing equations for multiphase flow in porous media and necessary closure models. Plotting the ratio of the thermal wave speed to the fluid speed allows one to infer that the reaction wave front ends where this ratio is at a minimum. The reaction front follows the thermal front closely, thus allowing assumptions to be made about the extent of decomposition solely by looking at thermal wave progression. Furthermore, this sensitivity analysis showed that a certain minimum permeability is required in order to ensure the formation of a traveling thermal wave. It was found that by studying the non-dimensional governing parameters of the system one can ascribe characteristic values for these parameters for given initial and boundary conditions. This allows one to roughly predict the performance of a particular method on a particular reservoir given approximate values for initial and boundary conditions. Channelling and flow blockage due to carbon residue buildup impeded each method's performance. Blockage was found to be a result of imbalanced heating.
Thread compound "dope?? in the vernacular, has been used routinely in assembling joints of casing and tubing. The practice in almost universal application in the oil and gas industry involves the manual application of the lubricant in a fashion that is rudimentary, non-systematic and unquantifiable. There is evidence presented in this paper that damage to the near-well zone and other unpleasant events may be associated with the thread compound.
This paper presents the results of both laboratory and field investigations quantifying the effects of the dope on near-well damage. During the assembly of tubing and casing a portion of the thread compound is exuded inside and outside the connection and gets access to the well fluids through the tubing and annular space. Studies presented here show that the dope forms a suspension which penetrates and damages the formation. The studies used standard fluid circulation velocities during typical completion operations.
To characterize and quantify the problem, core samples from the El Tordillo field, with different permeabilities were used. The samples were subjected to the circulation of the suspension created by the thread compound and the completion fluid, measuring the change in the core permeability. The work simulated the well conditions during water injection for water injection wells and during acid treatments for producer wells. A significant reduction in permeability, manifested by a fast and a very large increase in pressure, was measured, at the front face of the core sample. The same measurements showed a far smaller impact in the core body suggesting very minor penetration of dope particles.
This paper describes the laboratory and field work, with description of the test protocols, well conditions and laboratory emulation of field conditions that were used.
Arif, Muhammad (University of Engineering and Technology) | Bhatti, Amanat Ali (University of Engineering and Technology) | Khan, Ahmed Saeed (University of Engineering and Technology) | Haider, Syed Afraz (Kuwait Foreign Petroleum Exploration Company (KUFPEC))
It has long been proved experimentally that the tight gas sands are more pronounced to stress changes as compared to moderate and high permeability reservoirs because of the narrow flow channels of the formation . The consideration of the effect of stress in the evaluation and production performance of tight gas reservoirs is very important in order to make right decisions regarding their development. Due to hydrocarbon production, the effective stress increases causing a reduction in permeability and porosity of the porous medium.
The conventional pressure transient analysis techniques in gas wells based on constant permeability would become unreliable . Consequently, the incorrect evaluation of permeability leads towards wrong decision regarding well stimulation. Also the inflow performance modeling of tight gas reservoirs based on constant permeability will not be corrected as far as evaluation of well's production potential is concerned.
Few studies on tight gas reservoirs considering the effect of stress sensitive permeability used the Raghavan's stress dependent pseudo-pressure approach  for which pressure vs. permeability data was determined experimentally. But, if laboratory data is not available then there is need to develop an analytical approach to generate the pressure vs. permeability data required for the use of stress dependent pseudo-pressure in reservoir evaluation and production performance studies in tight gas reservoirs.
The objective of this paper is to develop an analytical approach, in the absence of lab data, to generate pressure vs. permeability data for the determination of stress dependent pseudo-pressure. This stress dependent pseudo-pressure is used for well test analysis to determine the stress sensitive formation permeability and also to generate production performance in tight gas reservoirs. The developed technique has also been implemented on the field data of a tight gas reservoir to validate the results by using actual well's production history.
In a layered, 2D heterogeneous sandpack with a 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil in place (OOIP) because of injected water flowing through the high-permeability zone, leaving the low-permeability zone unswept. To enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT). Once IFT was reduced to ultralow values, the adverse effect of capillarity retaining oil was eliminated. Gravity-driven vertical countercurrent flow then exchanged fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foam flood was 94.6% OOIP, even though foam strength was weak. Recovery with chemical flood (incremental recovered oil/waterflood remaining oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous-force-dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental to foam generation. However, the addition of lauryl betaine to NI (NIB) at a weight ratio of 1:2 (NI:lauryl betaine) made the new blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT-reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1D homogeneous sandpacks and in an oil-wet heterogeneous layered system with a 34:1 permeability ratio.
Simple methods, such as the use of density during compositional simulations, often fail to identify the phases correctly, and this can cause discontinuities in the computed relative permeability values. The results are then physically incorrect. Furthermore, numerical simulators often slow down or even stop because of discontinuities. There are many important applications in which the phase behavior can be single phase, gas/liquid, liquid/liquid, gas/liquid/liquid, or gas/liquid/solid at different times in different gridblocks. Assigning physically correct phase identities during a compositional simulation turns out to be a difficult problem that has resisted a general solution for decades. We know that the intensive thermodynamic properties, such as molar Gibbs free energy, must be continuous, assuming local equilibrium, but this condition is difficult to impose in numerical simulators because of the discrete nature of the calculations. An alternative approach is to develop a relative permeability model that is continuous and independent of the phase numbers assigned by the flash calculation. Relative permeability is a function of saturation, but also composition, because composition affects the phase distribution in the pores (i.e., the wettability). The equilibrium distribution of fluids in pores corresponds to the minimum in the Gibbs free energy for the entire fluid/rock system, including interfaces. In general, however, this relationship is difficult to model from first principles. What we can easily do is calculate the molar Gibbs free energy (G) of each phase at reference compositions where the relative permeabilities are known or assumed to be known and then interpolate between these values by use of the G calculated during each timestep of the simulation. Relative permeability values calculated this way are unconditionally continuous for all possible phase-behavior changes, including even critical points. We tested the new relative permeability model on a variety of extremely difficult simulation problems with up to four phases, and it has not failed yet. We illustrate several of these applications.