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Results
An Evolved Approach to Performing Underbalanced Perforating Interventions in Mexico: A Step-Change Improvement in Efficiency, Reliability, and Safety
Narcizo, O. Melo (PEMEX) | Aguilar, A. Martinez (PEMEX) | Mendo, A. Rosas (PEMEX) | Gordillo, J. C. (PEMEX) | Ramondenc, P. (Schlumberger) | Burgos, R. (Schlumberger) | Basurto, J. R. Cervantes (Schlumberger) | Rodriguez, F. L. (Schlumberger)
Abstract An innovative approach to underbalanced perforating in horizontal and highly deviated wells uses a new perforating head specifically developed to leverage the conveyance and real-time telemetry capabilities of coiled tubing (CT) equipped with fiber optics. The results and advantages of this approach have been demonstrated in wells in mature Mexican fields featuring significant reach and pressure limitations. In recent years, CT equipped with real-time fiber-optic telemetry has been a method of choice to perform interventions in deviated or horizontal wells, as it provides a cost-efficient and flexible alternative to heavier wired CT. In the Mexican fields, this real-time telemetry capability is used to accurately place the guns thanks to downhole casing collar locater and gamma ray tools. The need for pumping fluids to enable detonation, often performed during typical CT perforating operations, is eliminated through the use of a downhole microprocessor-controlled firing head, which is directed by commands sent from surface through the optical fiber. The result is a nearly instantaneous detonation downhole and positive confirmation provided in real time through an array of sensors in the bottomhole assembly (e.g., accelerometers, pressure, and temperature). The absence of working fluid eliminates any concern of hydraulically loading the well or the need for shut-in, thus significantly reducing the extent of deferred production. It also mitigates uncertainties linked to the influence of downhole conditions on the behavior of working fluids or the potential malfunctions of drop balls. This system is capable of multizone, selective detonation, therefore improving operational flexibility through reduced gun runs. It is also compatible with any other traditional CT service and can easily be combined with a bridge plug setting, a nitrogen lift, or a cleanout within the same run. The approach and its associated workflow enabled a significant reduction in intervention turnaround time by cutting as much as 75% of the time necessary to detonate the guns once the depth has been correlated, while providing fast and clear confirmation of downhole detonation. This evolved approach not only addresses the conveyance limitations of highly deviated and horizontal wells, it also greatly improves the safety, reliability, and efficiency of underbalanced perforating interventions by leveraging the real-time downhole monitoring and control capabilities of CT with fiber optic telemetry.
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 98/6 > Wytch Farm Field > Sherwood Formation (0.99)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 98/11 > Wytch Farm Field > Sherwood Formation (0.99)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 97/15 > Wytch Farm Field > Sherwood Formation (0.99)
- (6 more...)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications > Networks (0.93)
There are several cases of wells with potential or identified Annulus Pressure Buildup (APB) problems, especially at offshore fields. Historical failure examples happened at the Marlin field and at the Ponpano A-31 well, both in the Gulf of Mexico. The objective of this article is to present several alternatives for mitigating this problem and the design procedure for each one. In order to find and list those procedures, the literature was initially reviewed. More than 15 techniques were identified and classified in four groups: pressure relief, structural strength increase, fluid compressibility increase and thermal insulation. Afterwards, their design procedures were outlined, as well as its applications. When necessary, the authors performed some tests. Finally, a model well is used as example and the application of each technique is illustrated.
- North America > United States (1.00)
- South America > Brazil > Rio de Janeiro (0.48)
Enhancing Coal Bed Methane Recovery by Varying-Composition Gas Injection
Sayyafzadeh, Mohammad (The University of Adelaide) | Keshavarz, Alireza (The University of Adelaide) | Alias, Abdul Rahman (The University of Adelaide) | Dong, Ky Anh (The University of Adelaide) | Manser, Martin (The University of Adelaide)
Abstract Gas injection in coalbed methane (CBM) resources is a well-studied method. Findings indicate that although Carbon-Dioxide (CO2) injection expedites the Methane desorption process, its high adsorption affinity causes irretrievable permeability reduction. Nitrogen (N2) injection does not have the swelling issue, however, an early breakthrough of the injected gas occurs. Recently, through several simulation-based and experimental studies, it has been shown that a better result is obtained, when a mixture of CO2 and N2 is injected. In these studies, an optimum composition for the injected gas was found, by carrying out a series of sensitivity analyses for the given CBM with known geomechanical and sorption characteristics. In all of these studies, the composition of the injected mixture remains constant within the period of injection. In the current work, in order to obtain a better performance, an alternative method is proposed in which the composition of the injected gas is adaptively updated during the injection through several steps. This method can postpone the breakthrough time and also keep well injectivity high. To evaluate the proposed method and find an optimal and practical injection schedule, a semi-synthetic model is constructed. Different injection scenarios are compared with each other, using a compositional simulator (ECLIPSE-300), which uses the extended Langmuir isotherm and the modified Palmer-Mansoori model. The compositional simulation allows us to investigate the sorption competition between each component through the whole system. By a series of sensitivity analyses, an optimum scenario is found. The best obtained scenario, is the one that begins by injecting a mixture with less CO2, and continues by a sequential rise in the CO2 fraction. The outcomes confirm that the proposed method has the following benefits, in comparison with the continuous injection: 1- higher Methane recovery, 2- deferment in permeability reduction, 3- later N2 breakthrough.
- North America > United States (0.48)
- Asia > Middle East > Turkey (0.28)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline (0.66)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- (10 more...)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Abstract In this study, a reservoir modeling approach was used to evaluate the miscibility conditions for an Afghan oil reservoir. A model of slim-tube apparatus was built for compositional simulation in CMG-GEM. Minimum miscibility pressure/enrichment (MMP/MME) of crude oil-gas (carbon dioxide, methane and nitrogen) systems were determined by slim-tube simulation. To study the reservoir performance under each injection gas process, we built a quarter of five spot pattern model. The model was assumed to represent a homogeneous section of the reservoir. Simulation results of slim-tube test suggest that, to be miscible with reservoir oil, carbon dioxide requires less addition of enriched gas comparing to nitrogen or methane. But, the reservoir section model showed that a miscible nitrogen injection is better, with higher oil recovery factor than that of miscible carbon dioxide or methane. Introduction Almost sixty percent of original oil in place traps in reservoir as residual oil after primary and secondary oil production (Donaldson et al., 1985). Enhanced oil recovery methods (EOR) target the remaining oil that could not be produced by conventional techniques. Gas injection is one of the largest implemented enhanced oil recovery techniques to extract oil from a reservoir. In this method, oil is recovered by various means, such as swelling, vaporization and viscosity reduction (Holstein, et al., 2007). A gas injection process could be either miscible or immiscible. Under certain conditions, injected gas and reservoir oil become miscible. Interfacial tension between phases approaches zero in a miscible flood, in such conditions, phase boundary disappear and phases become miscible. Air, nitrogen, flue gas, carbon dioxide, and hydrocarbon gases have been utilized as injection gases. Gas injection EOR methods are now well understood, based on extensive laboratory and field experiences. The concept of MMP and MME explains the efficiency of oil displacement by injection gas (Taber et al., 1997). MMP is the pressure at which the injection gas and reservoir oil mix in any proportion. In pressures higher than MMP, the recovery is expected to reach 100% in microscopic scale (Yan et al., 2012).Miscibility could generally be achieved by three methods, including first-contact-miscible (FCM), condensing (or enriched) gas drive and vaporizing (or high-pressure) gas drive (Stalkup et al., 1983).
Abstract The steam-foam process is an Enhanced Oil Recovery (EOR) method which aims to improve the performance of a traditional steam drive by using a foaming surfactant. A Canadian thermal project under development in NW Alberta, which will use steam drive to recover extra heavy oil from the Bluesky Reservoir, is a good candidate for the application of steam-foam. A pilot test is planned to evaluate the benefits of the steam-foam process in this reservoir. The steam-foam process is based on the use of a surfactant which, when co-injected with steam into the formation, generates foam. A candidate surfactant for steam-foam should be able to generate stable foam at high temperature, have a good thermal stability, a low rate of adsorption on the rock, and good solubility in brine. An experimental plan was designed to screen for appropriate surfactants to use in the field. Bulk foam height tests at high temperature, thermal degradation tests and static adsorption tests with disaggregated rock were carried out to screen the best surfactant. Two candidate surfactants were chosen based on the results. A pilot test plan was also developed for a proof-of-concept test of the candidate surfactant in the field. The primary success criterion for the test is an increase in the Bottom Hole Pressure (BHP) of the injector well after the start of surfactant injection. Core-flooding tests are currently underway to confirm the performance of the candidate surfactant in the porous medium and determine the value of parameters required for the pilot design. The generation of strong foam in the formation should result in not only a BHP increase in the injector, but also improvement of the Steam to Oil Ratio (SOR) and ultimate recovery. The oil uplift response is dependent on the pattern geometry and geology of the reservoir and may not be observed immediately. However, the BHP increase will be immediately observed provided that strong foam has been generated near the wellbore, and this is the focus of the proof-of-concept test. A more extensive field test is planned for a later date to evaluate SOR improvement and recovery uplift.
- North America > Canada (0.69)
- North America > United States > California > Kern County (0.29)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Webster Formation (0.99)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Monterey Formation (0.99)
- North America > United States > California > San Joaquin Basin > Kern River Field (0.99)
- (2 more...)
Laboratory Study on Steam and Nitrogen Co-injection for Mid-deep Heavy Oil Reservoirs
Wang, Cheng (China University of Petroleum) | Zhong, Liguo (China University of Petroleum) | Li, Jianping (China University of Petroleum) | Chen, Gang (China University of Petroleum) | Zang, Ye (China University of Petroleum) | Wei, Fang (China University of Petroleum)
Abstract Surface steam injection is the most common enhanced oil recovery (EOR) technology used in heavy oil production. Nevertheless, limits exist due to heat loss for deep reservoirs. In the process of steam injection, adding a certain amount of nitrogen, which can reduce heat loss, maintain formation pressure and expand steam chamber, can effectively improve the development efficiency of steam injection. In this research, high-temperature-pressure pressure/volume/temperature (PVT) measurements and sand pack flooding experiments have been operated for heavy oil of the target reservoir in Bohai Oilfield, China, observing effect of nitrogen on property of heavy oil and steam and nitrogen co-injection on displacement efficiency and optimizing gas-water ratio during the co-injection. The results of PVT measurements indicate that the change of heavy oil viscosity is complex with the varying amount nitrogen dissolved. The reason is that dissolved nitrogen can reduce heavy oil viscosity on one hand; on the other hand, nitrogen can compress oil increasing its viscosity. The viscosity of heavy oil with dissolved nitrogen decreases significantly under low temperature and pressure (80°C, 15MPa), and the maximum viscosity reduction rate is 28%. Along with increase in temperature and pressure (150°C, 25MPa), the viscosity reducing effect becomes worse, especially at 150°C, the viscosity of heavy oil with dissolved nitrogen increases, on the contrary. The results of sand pack flooding experiments reveal that adding nitrogen during stream injection can improve oil displacement efficiency significantly. However, the increase of oil displacement efficiency is different with the varying gas water ratio; therefore, optimizing gas water ratio has a great influence on displacement effect in steam-nitrogen co-injection process. There is an optimal gas water ratio in the process, which is correlated with temperature. For example, the optimal gas water ratio is around 50 and 100 respectively while temperature of 200°C and 300°C. The key of mid-deep heavy oil reservoirs development using steam-nitrogen co-injection technology is gas water ratio optimization, and while optimizing gas water ratio properties of heavy oil, formation conditions and injection conditions, and many other factors should be taken into account. This research provides a direction to choose the optimal gas water ratio in the steam-nitrogen co-injection process.
- Asia > China > Bohai Basin > Jiyang Basin > Bamianhe Field (0.99)
- North America > United States > Louisiana > China Field (0.91)
Challenges on Sampling and Characterization of Heavy Oil in Deep Exploratory Wells: A Field Case Study
Rajkhowa, Anupam (Kuwait Oil Company (KOC)) | Al-Bader, Haifa (Kuwait Oil Company (KOC)) | Hameed, Waleed Ahmad (Kuwait Oil Company (KOC)) | Al-Nabhan, Abdul Razzaq (Kuwait Oil Company (KOC)) | Subban, Pakkirisamy (Kuwait Oil Company (KOC))
Abstract The objective of this paper is to present the methodology adopted to overcome challenges faced during sampling and characterization of heavy oil in deep exploratory wells. As a part of exploration activities, two exploratory wells had been successfully drilled and tested in deeper low permeability Lower Cretaceous reservoirs. Drill Stem Test (DST) technique is adopted to test all exploratory wells for collecting production, surface and bottom-hole pressure and temperature data and collection of fluid samples for fluid characterization. As the wells are tested with retrievable packer, coiled tubing (CT) is required during activation and stimulation operations due to absence of other lifting methods. In this case study wells, coiled tubing was lowered and the well was lifted continuously with nitrogen for clean-up and to assess production behavior as there was no self-flow. Surface samples have been checked to assess contamination with diesel used for underbalance operations. Continuous nitrogen lifting helped to collect representative bottom-hole samples. During testing, there was poor inflow of heavy oil of API 21–22 Deg, but the well could not be produced naturally in spite of repeated attempts. Matrix acid stimulation treatment was done to improve the productivity of the reservoir. Well flowed heavy oil and then gradually ceased to flow. Due to low mobility, self-flow could not be sustained. These pose significant challenges for well cleanup, flow studies and collection of representative sample for PVT analysis and fluid characterization. Surface sampling was not favorable due to mixing with lifting nitrogen gases and only alternative method available was to collect Bottom-Hole Samples (BHS). However, proper cleanup was an issue for sampling operation. Continuous lifting with nitrogen helped to produce clean oil in both the wells. Compositional analysis was done on the nitrogen lifted sample to quantify the contamination level before lowering the down-hole sampler in order to capture representative BHS. As a result of this approach, representative samples could be captured and fluid characterization could be carried out with quality results. It has been planned to adopt the same methods in such type of situation in testing exploratory wells. With the systematic approach representative samples could be successfully captured in both the wells where self-flow could not be sustained in spite of repeated attempts. Fluid characterization of heavy oil could be could be carried out in these two exploratory wells which are very valuable for further development planning of the reservoir / field.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.70)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Najmah Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Marrat "C" Formation (0.99)
- (13 more...)
- North America > United States > West Virginia > Appalachian Basin (0.94)
- North America > United States > Virginia > Appalachian Basin (0.94)
- North America > United States > Tennessee > Appalachian Basin (0.94)
- (9 more...)
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drill Bits (1.00)
- (3 more...)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Dynamic Simulation to Predict Self-Restart Potential of Acid Stimulated Wells by Bullhead Treatment in Deepwater Environment
Ugoala, Obinna (BG Group) | Thakur, Kapil (Schlumberger) | Siddiqi, Basel (Intecsea) | Cristea, Zaharia (Schlumberger) | Gad, Khaled (BG Group) | Robson, Perry (BG Group) | Pacho, Daniel (BG Group) | Hosny, Ayman (BG Group)
Abstract Matrix stimulation by acid is a technique used to enhance production from underperforming wells. It involves injection of acid at pressures lower than fracture pressure, with the aim of dissolving (in sandstones) or bypassing (in carbonates) the damage in the near-wellbore region, thereby clearing/improving the rock pore-throats and improving flow of hydrocarbons. Dynamic modelling of the acid stimulation process is essential to optimise the process by understanding conditions that will oppose self-restart of the wells treated by fluid bullhead and also to formulate operational guidelines. In particular, for the production systems discussed in this paper, it was imperative to determine whether the well(s) could self-restart (i.e., self-unload the intervention liquid volumes left in the well and nearwellbore zone) without intervention (e.g., nitrogen kickoff) after the acidizing treatment is completed. Dynamics in the various system components—the pipeline, wellbore, and near-wellbore reservoir area—affect each other and also the overall feasibility of attaining a self-restart (liquid unloading) after stimulation. Evidently, for an operation such as this, changes in saturations and effective permeability of the fluid phases in the near-wellbore region are of great importance. It follows that integration of the transient multiphase well model with a near-wellbore reservoir model becomes necessary to capture the full dynamics of the system. The integration of the well model to a near-wellbore reservoir model is, in this paper, discussed as a coupled model. By contrast, a typical dynamic standalone well model would use an inflow performance relationship (IPR) to represent the reservoir performance, which would simply have no history of fluids injected into the reservoir and their distribution in the near-wellbore area of the reservoir rock. As a result, there would be a lesser degree of confidence in the predictive capability of such standalone well model. Using coupled models, two gas wells were tested for their self-restart feasibility following acid stimulation. Furthermore, two methods of fluid injection were simulated to compare their effectiveness in aiding the self-restart of the wells. One approach involves sequential injection of fluids, followed by wellbore displacement with nitrogen to squeeze the treatment fluids (liquid) away from the near-wellbore region, making self-restart more likely. The second approach is to simultaneously inject the treatment fluids and nitrogen to lower the effective density of the treatment fluid mixture and also to energize the injected stimulation fluids, with the aim of facilitating self-restart. The fluids sequence of this second approach also ends with the wellbore displacement by nitrogen. This paper presents the results of the modelling and simulations carried out for gas wells and their fluids injection sequence. Important differences for the design of the operation were found when the stand alone and the coupled models were compared. The findings of this study have since been supported by observations in the field.