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Active Research's Summery

Active Research's Summery

The Optimum quality of the re-injected produced oily water to maintain a good injectivity in a radial system.

Introduction:

The cumulative volume of produced water can exceed by ten times the volume of hydrocarbon production in some fields. This water contains dispersed and suspended impurities such as crude oil droplets and mineral material particles. Produced water from the separators contains typically 40 -1200 mg/l oil droplets of less than 20µm and 1-50 mg/l solid particles of less than 10µm.
 
The separation of oil droplets and filtering solid particles is an expensive process. Even after treatment, produced oily water injection can cause a significant amount of injectivity reduction.
 
In water injection process, the optimum water quality must be measured to limit injectivity reduction and to minimize the un-necessarily treating process.
 
To insure a good injectivity for a long time, the concentration and size of solids and droplets should not exceed a certain limits for each rock permeability range. These limits can be determined by performing core flood tests and evaluate the damaging effect of different solid particles and oil droplets.
Also, new filtration materials should be tested to enhance treatment process by reducing impurities in produced water prior to injection.
 

Background:

The prediction of injectivity decline and influent and effluent water characteristics provides a method to specify the oily water quality requirements and determine the degree of well impairment. This allows an operator to design surface facilities with output water having optimum quality.
 
To correctly describe injectivity reduction, lab injection conditions and the injected water quality should be compatible with the actual conditions.
 
Rock matrix plugging extent, caused by water injection, depends on:
 

   1. The size and concentration of solid particles and oil droplets contained in this Brine.

   2. The pore size distribution, porosity, and permeability of the porous medium.

   3. The interaction of the injected fluid with the rock materials and pore fluids.

   4. The flow velocity of the injected Brine and the geometry of the injection system (Linear, Radial, or Fractured system).

Suspended particles and dispersed droplets capture retention happens mainly by three ways:
 

   1. Pore filling: which effect porosity with a minimal effect on permeability.

   2. Pore plugging: which greatly effect permeability as the flow paths start to narrow.

   3. Oil droplets capture process can be retarded by force generated by the pore fluid flow velocity and by the fluid nature of oil droplets.

In oily water injection, free oil will cause a reduction in relative permeability to water. The emulsified oil existing as 1to 15 micron oil droplets, can seal off pore throats if the sizes of the pore throats also fall into that range. This emulsion blocking effect is usually more serious than the reduction in relative permeability from free oil.
 
Oil droplets capture occurs only on the porous medium surface when its size is smaller than pore diameter and restricted by pore if its size is larger than the size of pore diameter. Since oil droplets can deform, they may pass through pore restrictions into quite a depth in the porous medium.
 
Nearly all Lab studies concerning injectivity reduction due to oily water injection were performed as linear core flooding. For radial system, which is the case at well bore, away from the well bore the flow area continuously enlarged which made the damage effect to be distributed on a larger area. So as flow advanced deep into the formation, it will cause less and less formation damage. At 5 cm away from the well bore of actual injector the flow area is nearly 50% higher that it is at the well bore.
 
Also at deep locations the oil droplets concentration become much less. So as flow advanced deep into the formation, it will cause less and less formation damage.
 

Objectives:

In this study a radial flood tests will be carried out to simulate a high rate injectors. The injected fluid is a simulated brine contains solid particles and oil droplets in different concentrations and sizes. Measuring injectivity decline provides a method to specify the oily water quality requirements.
 
Then the optimum oil concentration and droplets size, which will maintain a good injectivity with time, could be determined. Depending on these results, the operator could design surface facilities that produce a high quality injection water to minimize near well formation damage.
 
 
 

Reduction of Oil Content in the Produced Oily Water prior to Re-injection

Introduction:

During the production life of oil reservoir, the water cut may increase to high percentage. Most of the produced water is re-injected back into the reservoir because of the treatment cost and as an environmental protection solution, especially in offshore fields. However, re-injection of produced oily water is one of the most important and serious problems, as it can cause formation damage. The produced water is potentially suitable for re-injection into the reservoir after treatment because it has the same properties of formation water and also due to environmental considerations. In many countries, environmental regulations do not allow the discharge of the oily water without treatment. In the Kingdom of Saudi Arabia, the re-injection of produced water, which contains oil droplets and solid particles, is practiced in several on- and offshore fields and is often accompanied by injectivity decline and causes some formation damage due to pore throats plugging near the wellbore.
 
The procedure of water disposal becomes an important issue, especially in remote areas, in which the treatment facilities are very limited.
 
To minimize the formation damage while injection, the produced oily water should be treated by minimizing the solid particle contents as well as the oil droplets.
 

Objectives:

In this project, natural organic materials (not applied before) will be tested for its affectivity to remove the free and the soluble oil from contaminated water. Pre-investigations showed that the selected materials have the ability to remove the free and soluble oil from oily water. One of these materials is newly used as oil adsorbent medium. Results showed clearly the ability of the new material to obtain high quality water for re-injection. Therefore, field scale trial is very important to test the oil removal using the new material.
 
Other potential applications include treatment of marine spills, as well as industrial oily wastewater.
 
The final aim of this project is to develop a prototype, which is cost-effective and has the treatment applicability on-site.
 
The selected materials have the following specifications: Light, available and cost effective, Minimum efforts for installation, Low pressure-drop through the filter, Elimination of chemical consumption, Ability to treat oily water with different oil concentrations and to remove variable oil droplets, and Insoluble in hydrocarbons or other field chemicals.
 
 
 

Sand Production Prediction and Management

Introduction:

Sand production can be defined as the production of sand grains detached from the reservoir sandstone formation along with the produced hydrocarbon to the surface. Sand production is an exceedingly complex problem, which has troubled the oil industry worldwide. Moreover, sand production from highly unconsolidated sandstone reservoirs can occur as soon as the well is brought on production. In more consolidated reservoirs, sand production may occur for short periods of time followed by periods of sand-free production and may vary from reservoir to reservoir. Sand production and its associated erosion and plugging of equipment also represent a potential safety hazard. Subsequently, huge investments are made in many oil and gas fields worldwide to prevent sand from being produced to the surface.
 
Accurate prediction of sand production is a complex task. It involves the implementation of many techniques, such as production history, mechanical properties analysis using electrical logs data, laboratory testing and numerical modeling. Most of these techniques, however, are economically unattractive. On the other hand, prediction of sand production using complex numerical techniques may be not suitable for the industrial routine tasks.
 

Project Objectives:

In this study, attempts have been made to develop a simplified analytical model using the principles of rock mechanics with appropriate fluid flow equations based on laboratory-derived and practical field data for the accurate prediction of sand production. Finally Windows based friendly software package will be developed employing the developed method so that the young engineers can use it as handy tool to make decisive precautions for sand production problems.
 
 
 

Polymer/Gel Cement Systems, for Attacking Excess Water Production

Introduction:

In the U.S., on average, more than seven barrels of water are produced for each barrel of oil. Worldwide, an average of three barrels of water are produced for each of oil. The annual cost of disposing of this water is estimated to be U.S. $5-10 billion and approximately $450 billion worldwide.
 
Production wells are initially perforated near the bottom of the pay zone. When bottom water begins to dominate the fluid production these perforations are sealed-off with a cement-squeeze, a packer, or a plug. The well is reperforated above the sealed zone, and oil production is resumed. This process continues until the entire pay zone has been watered-out. Water shutoff materials and methods are include chemical, plugging agents, mechanical, and well techniques.
 
Polyacrylamides have been the most widely used polymers for water shut-off in production wells and for profile modification in injection wells; however, they can become unstable in salt water at high temperatures due to auto hydrolysis. These polymers can be crosslinked with transition metal ions, and the resulting gels are known to be more stable in harsh environments than the single uncrosslinked polymer itself. A new polymer gel is under investigations right now in our lab.
 
Using squeeze cement alone is not sufficient, because only a 30 % success rate on the average is achieved. The reason for this is that the size of standard cement particles restricts penetration of material into smaller channels, fractures, and high permeable zones. On the other side the use of gel alone has been found to be stable for only short times. But for organic system stable for long time (years). A combination treatment (cement/polymer gel) appears to be most effective. Gel is first placed into the formation to the required lateral depth. Then, the near-wellbore channels are sealed with a tail-in of cement. The cement helps lock the gel or polymer in the formation and helps prevent residual polymer production. Using a combination treatment cement (small particle size cement (SPSC), with particles less than 10 microns diameter)/polymer gel has an average cost of $4,000 to $6,000 per well, and increased oil production about 164% and decrease water production about 66%. (4)
 

Objectives:

The objectives of this study are:

     - To determine if gelant systems exist to shut-off water production that can be successfully applied in the reservoir conditions.

    - To develop polymer/gel systems to act as more effective barrier at the wellbore to control and divert fluid flow of water and gas. And consequently, increase oil producing rate and decrease operating costs.

    - To evaluate all gel systems, by determining the effect of cement filtrate on gel strength, and to investigate the effect of cement slurry on gel viscosity and gel strength, gellation time and gel stability.

 

Optimizing Production of Gas and Gas-Condensate Reservoirs in Saudi-Arabia.

Introduction:

The Kingdom of Saudi Arabia has the fourth largest gas reserve holding in the world. Recent exploration activities in southern of Ghawar field show a high amount of gas condensate in Khuff formation at a depth of approximately 14,000 feet. Gas condensate is a hydrocarbon mixture with a certain composition and proportion, which is in gaseous phase under reservoir conditions and in liquid phase under atmospheric pressure.
 

Literature Review:

Gas condensate reservoirs are the subject of many research processes in the world. The conventional method used to develop such gas condensate reservoir is by depleting the reservoir pressure or primary depletion. However, through the depletion an unfavorable process within the reservoir occurs: the retrograde condensation (liquid dropout), in which the reservoir pressure is decreased below the dewpoint pressure of the gas mixture due to production, thus a liquid will be formed and will accumulate in the reservoir. This condensation process can lead to poor recovery of gas. By leaving the condensate in the reservoir, one has not only decreased the hydrocarbon productivity, but the components remaining in the reservoir are of highest value. It is also possible that the condensate could breakdown the production. To avoid this disadvantage, the reservoir pressure should be maintained higher than the dewpoint pressure of the gas condensate. Therefore, different methods can be applied to maintain the reservoir pressure above the dewpoint pressure and therefore in its gaseous phase.
Those reservoirs, which exhibit the most challenging to the gas industry, are those, which do have separate liquid and gas phases in situ.
 

Objectives and Methodology:

The main objective of this proposal is to find the best method to maintain the reservoir pressure above the dew point. To decide which method is suitable, many reservoir and fluid factors must be considered, such as, mobility, permeability, reservoir depth, reservoir heterogeneity and the changes in the phase behavior.
 
In this proposal the importance of predicting gas and condensate relative permeability in near wellbore region of typical gas condensate wells will be investigated. Therefore, the dew point pressure of a gas-condensate should be experimentally determined in the laboratory. The laboratory measurement of the dewpoint pressure provides the most accurate and reliable determination method. Moreover, the phase behavior of the gas-condensate is most important, especially if it contains CO2, H2S and/or N2. Pressure-volume-temperature relationships are then to be determined for gas and liquid phases.
 
Also, in connection with this proposal, efforts will be undertaken on the alteration of the wettability to non-water-wet with the mean goal to remove/decrease the liquid from the rock surface near wellbore in case of gas/water system. The wettability alteration to non-water wet would improve the effective gas permeability. This point is important because, during gas production the water saturation around wellbore may increase due to formation water or a result of water condensation from the gas phase. This will cause a potentially reduction of effective gas permeability. The presence of water near wellbore will lead to change the rock wettability to water-wet, which will reduce the deliverability of gas reservoir.
 
 
 
Gas-Water relative permeability properties for low permeability tight sandstone reservoirs.

Introduction:

Understanding gas production from low permeability tight sandstone gas reservoir needs an appreciate understanding of the control on petrophysical characteristics of the sandstone gas reservoir. Evolution of these petrophysical characteristics based on a discussion of their relationship with, gas- water relative permeability, saturation, capillary pressure with regard to sediment type, sediment texture, and diagenetic impact. This project will focus mainly on low-permeability sandstone gas reservoir types.
 
Gas–water relative permeability and capillary pressure are dominant factors controlling the multiphase flow of (miscible and immiscible) water –gas phases in tight sandstone porous media and important properties for gas reservoir engineering, therefore, beyond the environmental sediment impact, they have a major effect on the performance of tight gas reservoirs production under development.
 
All the calculation of gas reservoir performance needs the input of relative permeability and capillary pressure values ahead of sediment material. By this project making fundamental laboratory measurements of gas-water flow in porous media and thereby it will be a significant contribution to the industry by providing both understanding of the phenomena as well as actual parameter value measurement.
 
Consequently, among vital problems to carry out are: measurement of gas-water relative permeability, capillary pressure, saturation, fracturing system in tight sandstone reservoir types, as well as the understanding of gas production.
 

Objectives of the Project

As it has been previously introduced, among the essential targets of this research project are: measurements and determination of the correct relative permeability and capillary functions for water-gas flow in porous media and their evolution according to various basic parameter changes. Consideration and interpretation of some input issues affecting gas well productivity in oil reservoirs such as tight sandstone gas reservoir constitute one of the main objectives of this project.
Furthermore, among objectives, which should be included in this project, are the understanding of the type of material with regard to flood experiments on gas-condensate fluids, formation water and drilling mud (brine) at reservoir conditions. The improvement of methods for simulation of gas-condensate well performance, and water drive gas well performance and well performance of damaged gas reservoir by drilling fluid constitutes one of the main objectives of our investigation. Moreover achievement of this work will constitute an important attempt to a field-scale reservoir simulation models with simpler reservoir engineering calculations.
 
 
 
Reservoir heterogeneities: Evaluation and Prediction

Abstract:

Integrated reservoir characterization that incorporates independent data sets, including three-dimensional geological model based on well logging analysis and control on poroperm evolution, constitute one of the main target in H-C exploration. In addition, multicomponent data is also important to characterize both static and dynamic reservoir parameters, including porosity, anisotropy, and fluid property variations within even a structurally and stratigraphically complex reservoirs.
 
An accurate geological model, based on an integrated reservoir characterization, can be valuable when used to evaluate vertical and lateral changeability of reservoir properties, or to simulate fluid flow for performance and prediction. The acquisition of a geological model can also be used in designing an appropriate reservoir management plan.
 

Introduction:

Naturally occurring, H.C. reservoirs, most of the time, display a high degree of geological complexity in terms of external and internal architecture, this is of particular importance when a simulation study is to be performed. Understanding and evaluating reservoir heterogeneities suggest analysis and interpretation of some subsurface oilfield material. Results and interpretation of this data will be simulated in order to establish a geological 3D model. Knowing and evaluating parameters governing the dynamic behavior of the reservoir constitute also an important part for reservoir performance and prediction. Consequently, and regarding these challenging tasks, the combined factors which control the reservoir heterogeneities and may constitute the aims of this project are:1-Structural parameters 2-Petrophysical properties and well logging analysis3-Interpretation and Simulation to 3D geological model, 4-Thermodynamic properties of fluids and impact on reservoir quality and production-5 Conclusion and recommendation.
 

Objectives of the project:

Among our targets in this project are assemblage of data of an a given oilfield in the Kingdom of Saudi Arabia, collection of core samples and measurement as well as analysis of this material which constitutes one of the main issues in our researching study. Synthesis of this data will allow us towards a development of a geological 3 D model for a given area. Such a 3 D model will permit to predict not only reservoir heterogeneities but also the reservoir performance.
 

Background:

Geological setting as well as the environmental deposits with lateral and vertical evolution have been used in different oilfields to establish reservoir heterogeneities. For a better understanding of these parameters which control the petrophysical characteristics, different methods have been applied. Results and interpretation have led to many successful achievements in the field of exploration.
 
In Such research and among our targets is the outcome which may allow us not only for a better understanding of reservoir evolution, but also on reservoir performance and prediction. In conclusion, this proposal is directed towards an account, which is: how different subsurface parameters may contribute on the way to a reduction or enhancements of reservoir performance.
 
 
 
A novel promising, high viscosifier, cheap, available and environmental friendley biopolymer for different applications at harsh reservoir conditions.

Introduction:

Primary recovery from oil reservoirs is known to be low, and the attempts to increase this recovery by both secondary and tertiary methods are well known. The challenge for both the petroleum engineers and the petroleum companies is to increase the oil recovery or to reduce the residual oil after the primary recovery. There are two common methods for that, the first is to decrease the oil viscosity by injecting steam or hot water and the second is to increase the water viscosity.
 
Water soluble polymers are common agents used in enhanced oil recovery processes to reduce the mobility of water in porous media by increasing its viscosity and hence to improve the sweep efficiency. Polymer solutions are used to improve waterflood performance and to maintain favorable mobility ratios.
 
Polymers are used successfully in many reservoirs all over the world, but the problem is to find the suitable and economical polymer for the harsh reservoir conditions of high temperatures and high salinity. This work will investigate a new polymer which has many advantages which enable it to overcome the above deficiency. These benefits include, (a) cheap (b) has high viscosity yield at high temperatures and high salinity and (c) environmental friendly.
 

Background:

Polymer flooding (Chemical Enhanced Oil Recovery; EOR) is a very important method for improving the water flooding sweep efficiency to increase oil recovery and reduce water production. It can yield a significant increase in percentage recovery by reducing the water production and improving the recovery when compared to the conventional water flooding in certain reservoirs.
 
There are two main types of polymers which can be applied in the reservoir application; these are synthetic polymers and biopolymers. Synthetic polymers are not stable at high temperatures and salinity while, the biopolymers are stable but are expensive and suffer from bacterial attack.
 
The first attempts to improve sweep efficiency in water flooding by polymers were made by Detling (1944). Polymer flooding became as a method to enhance the oil recovery after 1964 by the laboratory and field test development results by (Sandiford and Pye, 1964). Nowadays, successful polymer projects are used in many reservoirs all over the world during the past few years and attractive statistical data have been published which clearly prove the superiority of polymer treatment even in the next future all over the world.
 

Objectives:

The significance of this research point is to investigate and establish a new polymer which is cheap and available and can be applied under the harsh reservoir conditions of high pressure, salinity and temperature.
Also, the polymer is stable at high temperature for long time, has no effect by high salinity and also economical. In some pretests, this new polymer is applied under the reservoir conditions and gives high recovery even after 100% water cut, but more investigations should be done in this point. Finally, this polymer is safe and environmental friendly.
 
 
 
Miscible and Immiscible Gas-Oil Displacement in Saudi Oil Reservoirs using Continuous and Water Alternating Gas Injection
Several hundred million barrels of oil remain trapped in discovered reservoirs after primary and secondary recovery processes. This oil can be our energy source for years to come. However, as of date, this oil is deemed non-producible by current technology. Large research expenditure and efforts are being directed towards enhancing the recovery of this oil but with limited success. Although complete recovery of all the trapped oil is difficult, the target resource base is very large. Due to increasing demand for this trapped resource, gas injection appears to be a one of the attractive choices. Enhanced Oil Recovery (EOR) is defined as “incremental oil that can be economically produced” over that which can be economically recoverable by conventional primary and secondary methods”. The main goals of any EOR method are increasing the capillary number (that is defined as the ratio of viscous to capillary forces) and providing ‘favorable’ mobility ratios (M< 1.0 that is defined as the ratio of mobility of the displacing fluid to that of the displaced fluid).
 
In gas injection process, the residual oil saturations in gas swept zones have been found to be quite low; however, the volumetric sweep of the flood has always been a cause of concern. The mobility ratio, which controls the volumetric sweep, between the injected gas and displaced oil bank, is typically highly unfavourable due to the relatively low viscosity of the injected phase. This difference makes mobility and consequently flood profile control the biggest concerns for any successful application of this process. These concerns led to the development of the Water-Alternating-Gas (WAG) process for flood profile control. The higher microscopic displacement efficiency of gas combined with the better macroscopic sweep efficiency of water significantly increases the incremental oil production over the plain waterflood. Reservoir specific parameters such as wettability, interfacial tension, connate water saturation and gravity segregation add complexity to the design of any successful WAG flood.
 
This work is directed towards the investigation of the WAG process performance as a function of several variables including the effects of brine composition and the relative merits and demerits of the miscible process over the immiscible process in both continuous gas and water alternating gas floods at selected reservoir conditions.
 
In order to accomplish the proposed objectives, core-flooding experiments will be conducted in both 2-ft and 4-ft long Berea sandstone cores and some real cores from Saudi reservoir. Fluids used will be n-Decane and Saudi Crude oil as oleic phase and two types of brines (5% NaCl brine and formation brine or synthetic brine formulated to represent the actual Saudi formation brine) as aqueous phases. Pure CO2 gas will be used as the injecting gas. Both continuous gas injection and WAG floods will be conducted at different WAG ratio and different slug volume to reach the optimum ratio and slug volume. The experiments will be conducted in both miscible as well as immiscible modes.
 
 
 
Laboratory Investigation of Wettability Effects on Resistivity Index, Capillary pressure and Hydrocarbon Saturation from Complex Resistivity Measurements for Saudi Reservoir Rocks
Electrical logging is the most widely used method of identifying hydrocarbon-intervals in a wellbore. Standard methods of relating oil saturation in clay-free reservoirs to electrical resistivity are based on the Archie saturation equation Where the resistivity index, RI, is equal to the ratio of the resistivity of the sample (Rt) at brine saturation Sw over the resistivity of the sample at one hundred percent brine saturation (Ro). The resistivity index is related to the saturation of the sample and the saturation exponent, n. The saturation exponent must be determined by experimental core analysis. The standard technique for determining the saturation exponent involves measurements in cleaned cores, usually with air as the nonwetting phase and brine as the wetting phase. This air/brine system is only representative of the drainage conditions in strongly water-wet situations. When oil is displaced by water, for instance during water flooding, different distributions of fluid may prevail at the pore scale due to hysteresis effects controlled by pore geometries, initial saturation and wettability distribution at the pore scale.
 
Wettability and saturation history have significant effects on the redistribution of fluids in the pore space as pressures in the oil and water phases alter. Capillary pressure, Pc, is defined as the difference between the pressure of the oil, Po, and the pressure in the water phase, Pw, i.e. by convention, Pc = Po - Pw. Capillary pressure versus saturation relationships are important in the determination of initial water volumes, transition zone location and the modeling of oil displacement either by spontaneous water imbibitions and/or water injection. It is experimentally intensive to determine the water-oil capillary properties and corresponding electrical resistivities in the full saturation history cycle, particularly for reservoirs showing intermediate and mixed wettability.
 
The resistivity-saturation relationship not only depends on wettability but also the saturation history of the sample. Hysteresis in capillary pressure measurements has been known for a long time. The different distribution of fluids in the pore-space during desaturation and subsequent cycles also affects the resistivity-saturation relationships.
 
Therefore, predicting reservoir wettability and its effect on fluid distribution and hydrocarbon recovery remains one of the major challenges in reservoir evaluation and engineering. Current laboratory based techniques require the use of rock-fluid systems that are representative of in situ reservoir wettability and preferably under reservoir conditions of pressure and temperature. However, Electrical resistivity measurements at a single low AC frequency have long been recognized as providing an indication of the wettability of reservoir rock and fluid systems. But, the resistivity response over a range of frequencies for samples of varying wettability is not so well characterized.
 
This work focuses on the experimental aspects of resistivity index and water/oil capillary pressure measurements. Samples are tested in a multi-sample rig, at hydrostatic reservoir overburden stresses. The test equipment allows the measurement of resistivity in the two or six electrode configuration over a frequency range from 10Hz to 1MHz during drainage and imbibitions cycles. Six potential electrodes and two current electrodes are used to provide resistivity readings across the sample and for seven adjacent intervals along the length of the core plug. The resistivity profile along the core length enables assessment of saturation distribution and end effects. Sample wettability is evaluated using the Amott-Harvey wettability index on adjacent samples and change in Archie Saturation exponent before and after aging in crude oil.
 
Furthermore, the objective of this work is investigate and discuss in more detail the accurate measurement of resistivity and capillary pressure-saturation relationships of water / oil / rock systems. Due to, the resistivity response over a wide range of AC frequencies for samples of varying wettability is not characterized. Therefore, the complex resistivity response at differing saturations and wettability will be measured.
Last updated on : January 12, 2023 2:42am