Shale Gas/ Oil exploration is getting more and more attention as the existing fields, are in mature stage of production, therefore, time has come for finding the alternate energy resources. Shale gas is one of the future energy resources Therefore, it is essential to address the problem associated with the potential evaluation of shale gas reservoir.
Most of the shale gas reservoirs are fine grained sand or siltstone. It is not possible to find out true potential of reservoirs with the help of conventional logs / methodology. Before the field is even considered for shale gas evaluation, it is essential to acquire TOC and VRO data of the formation. The best way to acquire this data is conventional core or side wall core. Due to time constrained this data is not always acquired or sufficiently sampled. Therefore evaluation of these parameters, TOC and VRO, using the conventional logs is the only option left. With the help of log data, not only the calibrated values at depths can be generated but it gives a continuous log of these properties. These properties when combined with basin modeling studies than it give full hydrocarbon potential volume.
The current study deals with the Cambay Basin where silty sand reservoir has been identified as hydrocarbon bearing. An attempt has been made to determine shale-gas prospectivity of Cambay shale integrating wireline log, mud log, cutting and core data. The affect of gas present in shale reservoir is visible on logs specially neutron, density, acoustic and resistivity. Mud log data also indicates the presence of possible gas bearing zone in study area based upon gas count.
Using a specific workflow, hydrocarbon saturation, porosity and permeability of the reservoir section was computed. The same parameters were used for OGIP calculation & TOC calculation. Thermal Maturity (VRO) computation was done by using log data by making some assumptions. Log derived thermal maturity was calibrated with side wall core VRO in drilled wells .This transform is then used in other wells where core data is not available and undrilled portion of study area for calculation of thermal maturity. Depositional environment classification and facies analysis was done with the help of log data by using neural network technique. The techniques have demonstrated the methodology for shale gas potential evaluation and can be used for different reservoirs.
Recently, Saudi Aramco upstream activities in unconventional gas, and in particular tight gas sands, have been identified as a focus area. Integral to understanding the potential of tight gas as a resource, is an understanding of the petrophysical characterization of tight gas intervals. This paper presents a review of the petrophysical challenges in the evaluation of tight gas intervals encountered within an existing producing field producing from formation U. This formation can be highly variable and although it can be highly productive, in some areas the geology has produced poorer reservoir quality rock. Production from wells which penetrate these areas can exhibit "Tight Gas?? characteristics. Core and log data from existing fields are abundant and cover both good and poorer quality reservoir intervals. The factors which impact the evaluation of these "Tight Gas?? intervals, in this relatively well sampled environment, can be generalized to the evaluation of less well studied tight gas formations. The results of this review identify many areas where current techniques and tools fall short of providing an adequate characterization. In particular, the quantification of mineralogy and diagenesis is seen as important, as is the quantification of saturations and accurate measurement of micro-Darcy permeabilities. Areas where current techniques require improvement are highlighted and projects that are in progress to address these issues and improve the evaluation of tight gas are detailed. One area which is highlighted as holding potential is rock typing, which can categorize different types of tight gas interval based on clay content or mineralogy. Three wells have been selected for a fracturing exercise as a proof of concept to assess the production potential. The results of the fracturing exercise are presented relative to the petrophysical evaluation of these wells.
Ali, Mohammad A.J. (Kuwait Institute for Scientific Research) | Abeer, Al-Farhan A. (Kuwait Institute for Scientific Research) | Ali, Al-Haddad A. (Kuwait Institute for Scientific Research) | Suhaib, Al-Kholosy A. (Kuwait Institute for Scientific Research)
Reinjection of produced water is of increasing importance in the oilindustry as water production continues to increase worldwide. It provides anenvironmentally acceptable solution to the disposal of produced water, andcontributes to pressure maintenance. The performance of the injection wells andthe distribution of the injected water are strongly influenced by water qualityand the build-up of formation impairment around the wellbore.
Solid particles and small oil droplets present in the injected water canblock the reservoir pores and cause rapid and severe permeability decline.Total removal of solids and oil may not be economically feasible or practicallypossible. Therefore, to minimize or slow the rate of impairment, it isimportant to understand the relationship between the impairment mechanism andwater quality parameters, such as the total suspended solids and oildroplet.
This experimental study highlights the importance of water quality for thepurpose of water injection. An online particle size analyzer was used tomeasure particle size distribution and coalesces in the injected water.Different concentrations of suspended solid, oil droplet, water salinity, andoil viscosity were used in this study. The effect of suspended solids on thestability of oil-in-water emulsion was investigated. Finally, coreflood systemwas used to measure permeability decline during water injection containingsuspended particle.
The results showed that increasing suspended solid concentration did notaffect particle coalesce, but increasing oil concentration resulted in anincrease of oil droplets coalesces. However, when a combination of solidparticles and oil droplets were suspended in water, newly solid-oil attachmentparticles were formed. Increasing water salinity did not affect solid-solidcoalesce, but formed smaller oil droplets. Higher oil viscosity generatedrelatively in larger oil droplets than lower viscosity oil. Visual observationof emulsion containing suspended solids and oil droplets showed more stabilizedemulsion with higher salinity water than at lower salinity water. However,weaker emulsion was seen when high oil viscosity concentration was used.Finally, permeability reduction of core samples caused by oil droplets alonewas insignificant, but higher damage was seen by suspended solids, and severedamage was observed with combined solid and oil droplets.
Rubber or elastomeric seals are flexible polymers used in a variety of applications in many industries and have become more widely used in oilfield equipment as polymer technology has advanced. The seals are used in many oilfield applications and can be damaged during a rapid decrease of pressure after being exposed to environments containing gas. This phenomenon is known as explosive decompression (ED) or rapid gas decompression (RGD).
RGD damage can be manifested as splits, cracks, or bubbles in the seals, depending on the rubber type, length of exposure to the gas, and the rate of pressure decrease. Damage caused to a seal by RGD can range in severity from a slight weakening of the physical properties of the rubber to a catastrophic failure of the integrity of the seal. Both surface operations and downhole conditions are capable of causing RGD, which, can result in failure of the equipment using the seals.
This paper discusses tests performed on various elastomeric samples, including swellable rubber, to determine the effects that RGD will have on the seals under varying conditions. The tests exposed each sample to a range of pressure drops and gas exposure times. The samples were analyzed after each test for physical changes and signs of RGD damage. The purpose of mapping the effects of RGD on multiple samples and the various conditions to which the seals were subjected was to develop a better understanding of the conditions leading to RGD damage and to identify operations at risk for causing RGD damage to elastomeric seals. The testing and results are further discussed in this paper.
Wettability influences the flow motion of hydrocarbons in carbonate oil reservoirs: it is measured in laboratory with specific procedures including assessment of its initial value. Conventional or special core analysis requires good cleaning of the cores. Additional measurements like relative permeability or capillary pressure for instance require restoration of the initial wettability conditions of cores by aging them. The routine methods for assessment of wettability are USBM and Amott-Harvey (A-H) tests, which involve large amount of efforts and time. In this study we replace these tedious processes by tracking the aging through repeated NMR and resistivity measurements.
Four core plugs, two dolomites and two limestones, were selected from twenty carbonate plugs collected from different outcrops. After saturating the samples with brine, the cementation factor m was calculated. NMR T2 relaxation was performed as a reference on fully brine saturated samples. Crude oil was injected into the plugs until they attained Swi. An NMR T2 was measured on them before aging. Then one limestone and one dolomite were immersed in crude oil and placed in an oven at reservoir temperature, while the two other samples were loaded in resistivity core holders under same reservoir temperature and confining pressure to age them. Resistivity was measured continuously while NMR T2 were recorded at different time intervals to observe the response of the aging core samples to independent physical investigations.
The NMR and resistivity measurements were used to identify the wettability alteration. The resistivity change showed a continuous wettability change in the plugs, which was also confirmed by the continuous change in the NMR T2 response. Both methods showed that dolomite was more prone to becoming oil-wet than limestone. It was verified by USBM and Amott-Harvey tests on same plugs. Further tests will be necessary to validate the generality of the overall workflow.
This article shows the impact of installing Weatherford's online Red Eye water cut meter to work with the Micromotion Coriolis meter on the monthly well testing validity. This was applied on HwGOSP-2 test trap which is used to test the GOSP's wells on a monthly basis.
The wells' testing validity has been an issue since the installation of the new Coriolis flow meter. After several comparisons between the Coriolis flowmeter, multiphase flowmeter and the lab sampling results for more than a month, it was concluded that the coriolis was not giving accurate water cut readings, due to the variation in the well's liquids specific gravity.
This analysis revealed that specific gravity independent water cut meter is needed to be installed to work with the existing Coriolis mass flow meter. The water cut reading will be fed into the Distributed Control System (DCS) to report accurate net volumes of oil and water.
It was an opportunity to trial test the Red Eye 2G water cut meter which is using Near Infra Red (NIR) technology for real-time water cut measurement, the technology is based on NIR absorption spectroscopy, and independent of density changes. Red Eye water cut meter has been installed in the liquid leg of the test trap, to accurately measure and evaluate its capabilities of measuring the full range of water cut (0 to 100%) in a commingled oil and water stream.
The success criterion for this meter was defined as having the Red Eye data matching the lab data to a 90% confidence level. These success criteria have been met and the trial test was successfully concluded. The meter is presently operational at HwGOSP-2 since installation in April, 2010; performing to the desired results.
In June 2009, during HwGOSP-2 T&I, two parallel Coriolis mass flow meters were installed downstream of the test trap, as a part of the High Pressure Test Trap (HPTT) retrofit from a three phase separator to a two phase separator. The original liquid measurement configuration was with two individual turbine meters to measure the oil and water streams separately.
Now with the combined liquid stream, the intent was to measure the gross flow using the coriolis mass flow meter and derive the water cut of the produced water using the Chevron Research equation in the Net Oil Computer (NOC). However due to the differences in the wells' liquids specific gravity, the Coriolis meter was not reporting accurate water cut readings.
The lab samples analysis revealed that the water cut meter is needed to be installed to work with existing Coriolis mass flow meter. The water cut reading will be fed into the DCS to report accurate net volumes of oil and water.
With the focus on continuous drilling optimization, a collaborative effort was implemented to analyze and assess drilling challenges encountered while drilling extended horizontal wells in the Khurais field in Saudi Arabia. The primary requirement was to enhance the efficiency of conventional downhole motor directional drilling systems in the challenging horizontal reservoir section.
The Khurais field is located in a remote area in the central part of Saudi Arabia approximately 200 km from the Saudi capital Riyadh, and 300 km from the Eastern port city of Dammam. The producer wells are drilled in the middle of the field and the water injector wells are drilled close to the field boundaries.
An average of 12 rigs worked simultaneously throughout the duration of the project to drill and complete the required increment wells. The horizontal wells are comprised of the producers, trilateral producers and power water injectors. The wells were drilled to an averaged measured depth of 14,000 ft, with an average of 6,500 ft of open hole section across the reservoir. The 6??? horizontal hole section is particularly challenging and is drilled with steerable mud motors with the assistance of real time geosteering and logging while drilling (LWD) tools to maintain the horizontal open hole section of the well close to the top of the reservoir within a window of 3 ft.
The fracture intervals coupled with high permeability makes the drilling of this section particularly challenging, as mud losses are frequently encountered in this section. The main difficulties to improve the efficiency of the directional drilling process were high drag and differential sticking.
To overcome the challenges mentioned above, the drilling team utilized a new sliding technology that interacts with the drilling rig top drive to break the static friction improving the weight transfer to the bit, and thereby increase the rate of penetration (ROP). Through the virtual elimination of differential sticking and reduction of buckling problems, this system smoothly helps to deliver weight down to the bit. Additional benefits of this innovative technology are the prevention of stalling of the mud-motor, steady orientation of tool face and easier steering.
The authors will describe the innovative system utilized to improve the ROP during the sliding process by almost 50% and will present real cases supported by field data. They will also illustrate the importance of post-actions review and rig crew training in the achievement of record ROP in sliding mode. Historical cases will be presented and the benefits of the application of this technology in these wells will be explained.
Stimulation of high temperature oil and gas wells with HCl could cause significant corrosion to tubular goods. Organic acids are viable alternatives to HCl. However, conventional wisdom teaches that organic acids do not spend to its full capacity due to CO2 in solution. This leads to reducing their carbonate dissolving capacity further. Another potential drawback of using organic acids is the precipitation of the salt of calcium and organic ligands. Consequently, the concentration of the organic acid has to be confined to prevent the precipitation. Due to the above reasons, along with their cost per mass of rock dissolved, organic acids often have limited use in well stimulations.
Recent thermodynamic modeling studies have shown that when an organic acid or a mixture of HCl and an organic acid reacts with calcite, a previously unrecognized reaction occurs. This reaction enhances the calcite's dissolving capacity by the organic acid. The model provided new insight into the reaction equilibrium between organic acids with calcite, and gave a better understanding of which chemical species plays the dominant role in driving the overall dissolution reaction. In the case of acetic acid reacting with calcite, the model found that a chemical species, ca-monoacetate (Ca(CH3HCOO)+), exists because of the association of acetate and calcium ions. This species cannot be ignored. When quantitatively concentrated, it results in higher acetic acid dissolving capacity. Furthermore, mixing acetic acid with HCl can increase the conversion of acetic acid by the same calcium and acetate ion association and lead to more complete spending of acetic acid. The objective of this paper is to present the evidence of the existence of calcium monoacetate through experimental studies using Raman spectroscopy. Results showed that ca-monoacetate does exist during acetic acid dissolving of calcium carbonate. However, quantitative match between the experimental data and thermodynamic model prediction remains uncertain.
Water-soluble polymers are used to viscosify water-based fracturing fluids. This facilitates the growth of fractures and the placement of proppants. After placing proppants, polymers are removed to maximize productivity. To achieve optimum residual-polymer removal, it is essential to break the polymer gel to a low-viscosity fluid. Internal breakers or an acid flush are commonly used to break the polymer gels. Any insoluble or unbreakable residue can block pore spaces, leading to lower productivity. Therefore, it is very important that the polymers used for fracturing applications contain a minimum amount of insoluble residues or no insoluble residues.
In the widely used gravimetric method for determining residue, the polymer is first hydrated and then degraded before using gravimetric techniques. A standard gravimetric method takes more than 24 hr for one polymer sample. The accuracy of the results depends on consistency of laboratory techniques, such as filtration and weighing. Therefore, it was considered worth examining if a turbidity-based method could be developed to determine the insoluble residue quickly.
A linear correlation was found between turbidity and acid-insoluble residue of guar. The acid-insoluble residue, after keeping the guar sample in an aqueous fluid at pH 1.0 and 110ºF for 24 hr, bears a linear correlation with the turbidity of the solution. The turbidity of guar solution after 2 hr of hydration at pH 7.0 also bears a linear correlation with the acid-insoluble residue. However, the turbidity did not bear any correlation with the total water-insoluble residue.
This study led to the development of a turbidity-based method to determine the acid-insoluble residue in guar after approximately 2 hr. This is possibly the first study to correlate turbidity with acid-insoluble residue in guar and has the potential to be used for other polymers as well.
Hydraulic Flow Unit (HU) has been used extensively as a technique in permeability modeling and rock typing. Amaefule et al. (1993) introduced for the first time the concept of Reservoir Quality Index (RQI) and Flow Zone Indicator (FZI) by using the Kozeny-Carmen (K-C) model to characterize HU and predict permeability in uncored wells and intervals.
This technique has helped in enhancing the capability to capture the various reservoir flow behavior based on its respective characters. Yet, there are challenges in using the original correlation due to its inherent limitations and over simplified assumptions that prevent accurate HU definitions. This study highlights some of those shortcomings and proposes a modified K-C correlation that enhances the HU characterization.
It is found that the conventional K-C model ignores the inherent nonlinear behavior between the tortuosity and porosity. Hence, handling the tortuosity term in a more representative manner demonstrates a more rigorous correlation that extends the applicability of this powerful technique into more heterogeneous rocks - such as those found in carbonate reservoirs.
This paper presents a reservoir simulation case study that is conducted to validate the applicability of the proposed model as a rock typing technique in a heterogeneous carbonate reservoir in the Middle East region. Relative permeability curves, Leverett J-Function curves and initial water saturation distribution show good agreement within each HU generated using the proposed model.
It is recognized that modified Kozeny-Carmen technique give better matching of initial water saturation model than the conventional technique when compared to open-hole logs which, in turn; adds confidence to initial hydrocarbon-in-place calculations and reservoir behavior predictions. This result will ultimately enhance the prediction of reservoir performance under various scenarios in reservoir simulation.