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.
This paper springs from a series of laboratory experiments and high-resolution imaging techniques assessing the changes in microstructure, transport, and seismic properties of brine-saturated sandstones and carbonates when injected with CO2. Results show that the injection of CO2 into a brine-rock system induces chemo-mechanical mechanisms, which permanently change the rock frame. The injection of CO2 into brine-saturated-sandstones induces salt precipitation primarily at grain contacts and/or within small pore throats. Salt precipitation decreases permeability and increases P- and S- wave velocities particularly in sandstones characterized by porosity lower than 10%. On the other hand, the injection of CO2-rich brine into carbonates induces dissolution of the microcrystalline matrix (i.e., micrite) leading to porosity enhancement. Dissolution counteracts and overwhelms a pressure-dependent, chemo-mechanical creeping of the rock leading to compaction. The overall result is the decrease of the elastic moduli of the dry rock frame. These findings demonstrate that monitoring the time-lapse seismic response of chemically stimulated systems is far from being a pure fluid-substitution problem.
Unconventional gas resources will significantly affect the future of the energy sector worldwide in the coming years. The importance of non-Darcy flow has been highlighted in the literature in the context of highly productive fractured gas wells. The low gas flow rates from typical tight gas wells contradict this assumption. Neglecting the non-Darcy flow effect in tight reservoirs will lead to an overestimation of production and other misleading facts about tight gas reservoirs behavior. The interpretation of deviation from Darcy's flow through tight sand porous medium is addressed, in this work, by conducting a series of single phase gas flow experiments. The considered porous medium sample was slot-and-solution pore type tight sand collected from the Travis Peak Formation at a depth of 2654 m with permeability in microdarcy range and porosity of 7%. Two gases, nitrogen and helium, were used. Single-phase gas experiments were carried out at different pressure drops and overburden pressures. The experimental results showed that the examined slot-and-solution tight sand porous media is very sensitive to overburden pressure. Pore size distribution measurements, by mercury intrusion porosimetry and sorption isotherm, showed the existence of a wide range of pore size distribution (from 0.4 to 400 nm). The analysis shows that single phase gas flow through tight gas sand particularly at low pressure is of Knudsen diffusion type. Thus, the gas molecules may slip at the wall of the capillary and the Klinkenberg formulation may be the approach to describe the deviation from Darcy's law when the pore size and particle size are almost the same.
Saudi Aramco has employed horizontal sidetracking on existing dead vertical wells to enhance wells' productivity and rejuvenate field's performance. Understanding flood front movement, inter-reservoir connectivity, and pressure propagation in a highly stratified clastic reservoir in mixed fluvial and aeolian depositional environments are the key parameters that led to successful deployment.
This paper will present a case example discussing development strategies to revive an idle vertical well that was shut-in due to high water cut and low oil productivity. Both dynamic and static data were integrated to describe fluid flow phenomenon in the area to provide better understanding of the geological model, sweep and oil recovery. The multidisciplinary study indicated lateral and vertical reservoir heterogeneity and multilayer reservoir compartmentalization that caused uneven flood front movement and inadequate pressure support.
The team has considered all the uncertainties involved and have formulated an optimum completion plan. The team recommended sidetracking the idle well about 1 km away to target a sweet spot through an aggressive step-out strategy. This long step-out strategy was the first to be implemented in this sandstone reservoir where risk of hole collapse or stuck pipe is extremely high. Prudent reservoir monitoring and applying safe drilling and mud management practices were the major elements to successfully achieve the objectives. The plan was carefully executed by deploying fit-for-purpose completion that consisted of premium sand screens and blank pipe with mechanical packers to isolate a wet zone. The well was then treated with a clean-up fluid to remove any mud filter-cake to enhance productivity. The current production performance exceeded expected rate by 100%. The success and the captured lessons-learned from this strategy will be capitalized on for implementation in future similar sidetrack opportunities.
Cementing deep sour gas wells presents a number of challenges to well construction engineers. High bottom hole static temperature (BHST from 250 to 400oF) and pressure (mud density > 2.0 g/cm3), excessively long job times due to the constraints imposed by tight annular clearances (casing OD/hole size > 0.85), long cement columns (interval length > 450 ft), and harsh conditions (H2S, CO2, salt layer, high leakoff). All of these factors contribute to the operational risks not only during placement of the cement slurry in the wellbore, but also during the life of the well. Field data indicates that current cement systems were not able to address these challenges, and as a result, the outcome obtained from various cementing jobs was below expectation.
Advanced cement systems were developed to address the problems encountered in cementing deep sour gas wells. These systems were applied in the field with great success. Multi-functional fluid migration control systems together with engineering particle sizing technique significantly improved the performance of cementing jobs, including: superior fluid migration control, predictable thickening time, stable API properties at high slurry densities, and great resistance to H2S, CO2 and salt corrosion. A unique retarder used in the lead slurry helped in developing compressive strength rapidly on the top of cement column. An effective laminar flow displacement technique was also used to displace drilling fluids effectively to enhance its placement and improve the cementing bond.
This paper details a thorough and systematic laboratory development of innovative cement systems and presents case histories to document their effectiveness for cementing deep sour gas wells.
Ekpe, Joseph (Lukoil Saudi Arabia Energy Ltd) | Kompantsev, Andrey (Lukoil Saudi Arabia Energy Ltd) | Khakimov, Ayrat (Lukoil Saudi Arabia Energy Ltd) | Mohammad, Emad (Lukoil Saudi Arabia Energy Ltd) | Ganizade, Fazil (Lukoil Saudi Arabia Energy Ltd) | Madkour, Ali (Lukoil Saudi Arabia Energy Ltd) | Ashoor, Ayman (Lukoil Saudi Arabia Energy Ltd) | Al-Ali, Ali (Lukoil Saudi Arabia Energy Ltd) | Al-Khalifah, Fadhel (Lukoil Saudi Arabia Energy Ltd)
Lukoil Saudi Arabia Energy Limited(LUKSAR) started a Deep ‘Tight Gas' exploration campaign in the Rub Al-Khali Empty Quarter in 2006 and nine wildcat exploration wells have been drilled and evaluated with one Appraisal well in its Field Fig. 1. These prospective deep gas discoveries in the Empty Quarter have occurred in relatively High Pressure/ High Temperature (HP/HT) horizons at depths between 15,000 and 20,000 feet, where the stress and temperature are extremely high in addition to low reservoir permeability. This has made the exploration activity more challenging.
Well test and clean up results from different completion strategy has not yield convincing results due to many factors. Some of these include: well placement, fluid selection, completions and frac designs. Nonetheless, the starting point in evaluating the success of well operations in the life cycle of a well remains selection of suitable drilling fluid of which its solids and filtrate particles are very friendly to the given reservoir (i.e minimum damage effect). Although the drainage radius of these wells may be several hundreds of feet, the effective permeability close to the wellbore may have a disproportionate effect on the well productivity.
This paper summarizes the challenges encountered in the use of water-base mud (WBM) and the subsequent mud filtrate effect on the reservoir permeability through different test analysis on core samples and logs interpretations. But most importantly the result raises the need for continual research and development in the area of formation damage prevention and avoidance in deep gas drilling of ultra-low permeability reservoirs.
For many years, hydrochloric acid was the main fluid used in carbonate reservoirs well stimulation. Hydrochloric acid has many advantages including high dissolving power and water soluble products, but it also has some disadvantages such as high reaction rate and high corrosivity. There are other acid systems that can be used to minimize these effects; one of the most important systems is the emulsified acid. The emulsified acid offers the advantage of minimum additives and minimum corrosion possibilities. Researchers correlated the droplet size of the dispersed phase (acid) and emulsifier concentration to the viscosity, stability, and reaction kinetics of emulsified acids.
The effect of emulsifier concentration, acid volume fraction and temperature on elastic properties of emulsified acid was not studied before. The main objective of this work is to study the effect of these parameters on the elastic properties of the emulsified acid. In order to perform that, a HPHT oscillatory rheometer was used.
The general behavior of emulsified acid is that the viscous modulus (G??) is always higher than the elastic modulus (G'). As the emulsifier concentration increases, viscosity increases and the viscous behavior dominates for these fluids. As the acid volume fraction increases, the viscous modulus (G??) increases. At low emulsifier concentration (2 vol%), the elastic modulus (G') and viscous modulus (G??) increase with increasing the temperature up to 170 ºF and then decrease. At higher emulsifier concentration, the elastic modulus (G') almost does not change with temperature and the viscous modulus (G??) always decreases with increasing temperature. These results will help production engineer to better design acid treatments that depend on emulsified acids.
Lost circulation is a leading cause of downtime in drilling operations and is encountered in most drilling jobs. It can result in complete loss of the hole along with costly drilling equipment. To successfully prevent losses of drilling fluid, it is vital to rapidly prepare and place a lost circulation treatment into the loss zone when losses are encountered. A fibrous lost circulation pill has been developed to address common operational concerns that exist with current lost circulation materials and applications. This one-sack product does not require any activators, retarders, set time calculations, or temperature activation. It has been specifically designed for rapid mixing and pumping with minimal equipment.
Laboratory testing has demonstrated the ability of the fibrous pill slurries to rapidly dewater/de-oil and form a sealing plug on both ceramic filter discs and slotted metal discs. Testing also shows that the product forms a sealing plug in depleted sand formations. This pill can easily be weighted using barite to help control hydrostatic pressures. The fibrous product is suitable, and has been tested, with a wide range of fluids including freshwater, brines, and base oils. This product also meets strict environmental requirements for use in both the Gulf of Mexico and Norway. It can be rapidly mixed and pumped on location using standard rig equipment and only requires base fluid, barite and the product. The pill formulation is compatible with all mud systems and is easily removed using standard solids control equipment.
This new approach to control severe losses has been successfully applied in several field tests, which have reflected a variety of lost circulation conditions. A few of these field applications will be discussed in detail.
Carbonate reservoir stimulation has been carried out for years using HCl-based fluids. High HCl concentrations should not be used when the well completion has Cr-based alloy in which the protective layer is chrome oxide, which is soluble in HCl. HCl or its based fluids are not recommended either in shallow reservoirs where the fracture pressure is low (face dissolution) or in deep reservoirs where it will cause severe corrosion problems.
Different chelating agents have been proposed to be used as alternatives to HCl in the cases that HCl cannot be used. Chelating agents such as HEDTA (hydroxyethylenediaminetriaceticacid), and GLDA (L-glutamic acid -N,N-diacetic acid) have been used to stimulate carbonate cores. The benefits of chelating agents over HCl are the low reaction and corrosion rates. In this study, the effect of core length on the volume required to create wormhole was investigated using Indiana limestone cores of an average permeability 3 md and core lengths from 1 to 20 in. Chelating agents were tested at pH value of 4 and a concentration of 0.6M and their performance was compared with that of 15 wt% HCl.
Experimental results showed that the volume of HCl required to create wormholes increased when core length was 20 in. This effect was different from that noted when chelating agent were used. Increasing the core length for chelating agents decreased the volume required to create wormholes in the carbonate cores at the same conditions. This is because of the increased contact time by increasing the core length. Chelating agents can be used to stimulate shallow reservoirs where HCl causes face dissolution. They can be used in deep reservoirs where HCl can cause severe corrosion to well tubulars.
Traditional proppant placement evaluation in hydraulically induced fractures utilizes detection of radioactive tracers pumped downhole with the "frac?? slurry. Although this technique has proven useful, it involves environmental, safety, and regulatory concerns/issues. The fracture height determination method described in this paper eliminates downhole placement of radioactive materials. A high thermal neutron capture compound (HTNCC) is inseparably incorporated into each ceramic proppant (CEP) grain during manufacturing in sufficiently low concentration that it does not affect mechanical strength, conductivity, durability, or density of the particles. The proppant is detected using standard compensated neutron logging tools (CNT) and/or pulsed neutron capture (PNC) logging tools, with detection based on the high thermal neutron absorptive properties of the compound relative to downhole constituents. Since the HTNCC is placed permanently in the proppant, logging for proppant detection can occur at any time(s) after the frac job, with no requirement for special handling or mixing considerations. To clarify, the new detectable proppant is not radioactive, and the benign detectable material is uniformly mixed into the ore during proppant manufacturing, so there is no chance for segregation of the detectable agent from the proppant.
Specifically, the proppant is detected using after-frac CNT logs, sometimes combined with corresponding before-frac logs. The increased thermal neutron absorption by the HTNCC reduces count rates in the near and far detectors, with approximately the same percentage reduction observed in each detector, leaving the near to far detector count rate ratio (N/F ratio) unchanged. One detection method utilizes a comparison of before-frac log count rates and after-frac count rates, with reduced after-frac count rates observed in zones containing proppant. Another detection method, especially useful if formation gas saturations change, requires only the after-frac log. Since the N/F ratio is essentially unaffected by proppant, after-frac count rates predicted from the ratio will also be unaffected. These synthetic count rates will be greater than the observed after-frac count rates in intervals containing proppant. When PNC tools are utilized in a third method, tagged proppant can be identified from count rate suppression in the detectors and also from increases in the measured formation and/or borehole component capture cross sections. In tools utilizing spectral gamma ray detectors, the HNCC may also be detected using capture gamma ray spectral deconvolution.
Monte Carlo modeling data are presented demonstrating the utility of these techniques employing CNT tools. Field examples illustrating proppant detection using compensated neutron tools are also presented.