Skrettingland, K. (Statoil ASA) | Ulland, E. N. (Statoil ASA) | Ravndal, O. (Statoil ASA) | Tangen, M. (Statoil ASA) | Kristoffersen, J. B. (Statoil ASA) | Stenerud, V. R. (Statoil ASA) | Dalen, V. (Statoil ASA) | Standnes, D. C. (Statoil ASA) | Fevang, Ø. (Statoil ASA) | Mevik, K. M. (Knutsen Subsea Solutions) | McIntosh, N. (Knutsen Subsea Solutions) | Mebratu, A. (Halliburton) | Melien, I. (Halliburton) | Stavland, A. (Intl Research Inst of Stavanger)
Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper.
After the injection of approximately 400,000 Sm3 (113,000 Sm3 preflush, followed by 240,000 Sm3 of sodium silicate gelant and 49,000 Sm3 of postflush fluid) at injection rates up to 4,000 Sm3/d, the injection from the vessel was stopped and the well was put on regular seawater injection. Following more than two years of regular production, transient pressure measurements, tracer testing and water cut data are presented from the ongoing comprehensive data acquisition program. These results demonstrate clearly the achieved in-depth flow diversion through a delayed breakthrough of injected tracers and lower water cut in the relevant production well.
Preliminary studies have been done to characterize rock-fluid properties, and flow mechanisms in the shale reservoirs. Most of these studies, through modifying methods used for conventional reservoirs, fail to capture dynamic features of shale rock and fluids in confined nano-pore space. In unconventional reservoirs, interactions between the wall of shale and the contained fluid significantly affect phase and flow behaviors. The inability to model capillarity with the consideration of pore size distribution characteristics using commercial software may lead to an inaccurate oil production performance in Bakken. This paper presents a novel formulation that consistently evaluates capillary force and adsorption using pore size distribution (PSD) directly from core measurements. The new findings could better address differences in flow mechanisms in unconventional reservoirs, and thus lead to an optimized IOR practice.
Tagavifar, Mohsen (The University of Texas at Austin) | Herath, Sumudu (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Pope, Gary (The University of Texas at Austin)
We made measurements of microemulsion rheology with mixtures of oil, brine, surfactant, co-solvent, and in some cases polymer to systematically investigate the effects of salinity, co-solvents and polymers. A microemulsion rheology model was developed and used to interpret the experimental results. We show that the optimum microemulsion-to-oil viscosity ratio is roughly 5 to 6 without co-solvent, but it can be reduced to a more favorable ratio of ~2 by adding co-solvent. Even though the amount of co-solvent needed is case dependent, a clear trend of microemulsion viscosity reduction with increasing co-solvent concentration was observed. Limited evidence suggests that large hydrolyzed polyacrylamide molecules with a narrow molecular weight distribution have negligible partitioning to type II and III microemulsions.
Production from tight formation resources leads the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising EOR approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature focus on unconventional plays. This study is a laboratory investigation of gas flooding to recover light crude oil from nano-permeable shale reservoirs.
In this work, the N2 flooding process was applied to Eagle Ford core plugs saturated with dead oil. To investigate the effects of flooding time and injection pressure on the recovery factor, two groups of core-flood tests were performed. In group one, flooding time ranged from 1 to 5 days in increments of 1 day; in the other group, the injection pressure ranged from 1,000 psi to 5,000 psi in increments of 1,000 psi. The experimental setup was monitored using X-ray CT that helped to visualize phase flow and estimate the recovery efficiency during the test.
The potential of N2 flooding for improving oil recovery from shale core plugs was examined, and the recovery factor (RF) of each case was presented. The results from group one showed that more oil was produced with a longer flooding time. However, the incremental RF decreased with the increase of flooding time. The oil recovery was significant at the initial period of the recovery process, and a longer flooding time had less effect on extracting more oil. With flooding time constant in 1-day, the results from the second group indicated that RF increased with injection pressure, especially rising pressure, from 1,000 psi to 2,000 psi. The gas breakthrough time became shorter with the increase of injection pressure. The analysis of the CT number showed that the oil recovery process mainly occurred before the gas breakthrough. Once a fluid flow path was established, the injected gas flowed through the limited communication channels; thus, no extra oil could be extracted without increasing the injection pressure. This experimental study illustrates that gas flooding has liquid oil production potential in shale reservoirs.
Jahanbakhsh, A. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Sohrabi, M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Fatemi, S. M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Shahverdi, H. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University)
Gas/oil interfacial tension (IFT) is one of the most important parameters that impact the performance of gas injection in an oil reservoir. The choice or design of the composition of the gas injected for EOR is usually affected by the gas/oil IFT. In conventional reservoir simulation, IFT does not explicitly appear in the equations of flow and therefore its effect must be captured by the shape and values of relative permeability curves. A few studies have been previously reported for IFT effect on two-phase flow but very little have been done to investigate gas/oil IFT effect under three-phase flow conditions. The objective of this study is, firstly, to investigate the impact of gas/oil IFT reduction on two- and three-phase relative permeabilities using coreflood experiments. Secondly, to investigate the effect of changing gas/oil IFT value (immiscible and near-miscible) on the performance of WAG injections and residual oil saturation reduction at laboratory scale.
Two- and three-phase (WAG) coreflood experiments have been performed on water-wet and mixed-wet cores at three different gas/oil IFT conditions. These experiments were conducted on Clashach sandstone cores with a permeability of 65 and 1000 mD. The two- and three-phase relative permeabilities were estimated from the results of the coreflood experiments using our in-house software (3RPSim) and were compared with each other on the basis of their gas/oil IFT values. Moreover, the impact of gas/oil IFT reduction on the performance of gas and WAG injection and in particular on the reduction of residual oil saturation was investigated. The results of our studies were also compared with the existing literature on the laboratory investigation of WAG injection.
The results show that in two-phase gas/oil systems, the relative permeability of non-wetting phase is more affected by a reduction in the gas/oil IFT compared of the relative permeability of the wetting phase. Comparing the curvature of the gas and oil relative permeability curves shows that although the curvature decreases by a reduction in gas/oil IFT but it is still far away from straight line even at ultra-low IFT values. In three-phase flow system, reduction of gas/oil IFT affects the relative permeabilities of all the three phases (gas, oil and water).
The results show that at high gas/oil IFT or immiscible WAG injection, the most reduction in residual oil saturation is achieved in the first injection cycle and further WAG cycles do not result in a significant additional reduction in oil saturation. On the contrary, at low gas/oil IFT or near-miscible WAG injection, the residual oil saturation keeps decreasing as the number of WAG cycles increases. Moreover, the reduction in residual oil saturation was more effective when the immiscible WAG experiments started with gas injection (secondary WAG).
One of the primary problems for mature oilfield operators is the production of undesired fluids, such as water or gas. Cantarell is a mature field wherein one of the greatest challenges is managing produced water. Mature oil fields experience severe water production, which can be challenging in naturally fractured carbonate reservoirs that produce through a thick layer of oil. A new technology combining two conformance systems was used to alleviate water production in a well in this field, returning production to optimal levels.
The study well (Well A) was shut in because of high water cut (90 to 100%), and post-analysis of this problem showed water coning from fractures in the Lower Cretaceous formation. The well has a unique interval, and perforating a deeper interval was not possible because the water-oil contact (WOC) was close. The solution selected for this case was a combination of two conformance technologies for water control that permit sealing high permeability channels and fractures and, more importantly, help provide selective water control—one is a swelling polymer designed to shut off water channels, fractures, or highly vugular zones, and the other is hydrocarbon-based slurry cement that reacts on contact with water. The result was the recovery of a producer well with 1,197 BOPD with 14% water cut. After 19 months, production averaged 1,300 BOPD for that month with 40 to 66% water cut.
Correctly diagnosing the problem and combining conformance technologies can help operators resume production of wells considered lost because of undesired fluids production. Therefore, this technology could be used to benefit reservoir optimization and production.
Foamed fluids with the gas phase of carbon dioxide (CO2) have been applied as fracturing fluids to develop unconventional resources. This type of fracturing fluids meets the waterless requirements by unconventional reservoirs, which are prone to damage by clay swelling and blocking pore throat in water environment. Conventional CO2 foams with surfactants have low durability under high temperature and high salinity, which limit their application. Nanoparticles provide a new technique to stabilize CO2 foams under harsh reservoir conditions. It's essential to determine in-situ rheology of CO2 foams stabilized by nanoparticles in order to predict proppant transport in reservoir fractures and improve oil production.
The shear viscosity and foam texture of non-Newtonian fluids under reservoir conditions are critical to transport proppant and generate effective micro-channels. This study determined the in-situ shear viscosity of supercritical CO2 foams stabilized by nano-SiO2 in the Flow Loop apparatus with shear rates of 5950~17850 s-1 at the pressure of 1140±20 psig and the temperature of 40 °C. Supercritical CO2 with the density of 0.2~0.4 g/ml and the viscosity of 0.02~0.04 cp under typical reservoir conditions were applied to generate foams. The foams were tested with high foam quality up to 80% to minimize the usage of water. The effects of shear rates, salinity, surfactant, and nanoparticle sizes and on the rheology of gas foams with different foam qualities were experimentally investigated. The foam texture and stability were observed through an in-line sapphire tube. Further, proppant transport by CO2 foams and the placement in fractures were analyzed by considering the rheology of non-Newtonian fluids and the mechanisms of gravity driven settling and hindered settling/slurry flow.
The conditions of nanoparticle foaming systems were optimized through orthogonal experimental design. The dense and stable foams were generated and observed under high pressure and elevated temperature conditions. It was observed that CO2 foams with high quality of 80% demonstrated the highest viscosity and stability under optimal conditions. The foams with nanoparticles demonstrated both shear- thinning and shear-thickening behaviors depending on foam quality and components. The salinity and nanoparticle size affect foam rheology in two ways depending on components, foam quality, and shear rates.
While the viscosities of CO2 foam stabilized by nanoparticles have been widely studied recently, no work has been done to observe the stability and texture of supercritical CO2 foam after shearing under high pressure and high temperature, not to mention proppant transport by CO2 foam. This study provided a pioneering insight to the proppant transport by viscous supercritical CO2 foam stabilized by nanoparticles.
Use of foams to control CO2 floods conformance is attracting a renewed interest in recent years due its flexibility and ease of application. This application becomes even more attractive in current times of low oil price, as it can be an inexpensive mean to maximize CO2 utilization efficiency and increase production at no capital expenses. However, it is generally recognized that to maximize chances of success of a pilot application, an appropriate foaming formulation must be designed for a given reservoir and characterized in petrophysics lab. This usually requires an extensive laboratory work that is not always compatible with cost constraints.
We present a new cost-effective workflow that focuses on evaluating two formulation performance indicators derived from the population balance model: foam creation (related to foaming power) and resistance to foam destruction (related to foam stabilization against coarsening and coalescence).
We assess these two parameters in representative reservoir conditions by measuring foam mobility reduction in porous media and foam lifetimes. Experimental results and simple scaling arguments show that these two measurements, both of importance to the application, are mostly independent. This shed light on a recurring question pertaining to the relevance of bulk foam experiments to predict foam efficiency in porous media. With this in mind, we present a new approach for measuring mobility reduction in porous media with a higher throughput than usual corefloods experiments. This methodology is based on sandpack experiments as well as serial coreflood experiments that allow multiple successive formulations testing. We show that the link between sandpack and coreflood results is far from being straightforward, and depends on static (geometrical) as well as dynamic (flow) parameters.
Overall, this work provides new insights on the major performance indicators used to evaluate foam efficiency for gas conformance control in oil reservoirs. We build on this understanding to present a novel approach that can help developing more efficient foam EOR solutions. In particular, it allows tailoring foaming agents properties (such as foaminess and foam stabilization) to specific conditions of a given application (oil saturation, vertical heterogeneity, etc…).
The EOR activity has been very restricted in naturally fractured reservoirs (NFR) because the fluid behavior on these reservoirs are strongly dependent of specific properties of the fractures such as direction, length, thickness, morphology and angle, and good tools were not available to get this information accurately from the reservoirs in the past. Today it is possible to get a lot of information on the fractures by using direct data sources like core samples, drill cuttings and downhole cameras; or even by indirect data sources like well log, well drilling, production history and seismic.
These advancements in the data acquisition have facilitated EOR applications and the EOR activity has increased in the past few years in NFR. GAGD is a promising technique that uses the gravitational flow to improve the sweep efficiency in the reservoir and increase oil recovery. Its benefits have been proven in some academic works and in field applications, such as the Cantarell Oil field that achieved outstanding results.
In this work, we have developed an experimental model that simulates the flow behavior of NFR from a Brazilian offshore oilfield. The model uses rectangular Berea Sandstones blocks that simulate the matrix rock in the experiments and these blocks are separated by small gaps using metal spacers. These gaps act as the fractures in the experimental model. The experimental conditions are close to the reservoir and the used configuration simulates the interaction between matrix and fracture, as well as the flow in the fractures.
In the experiments the blocks are packed in a high-pressure physical model in the desired configuration. The gas is injected from the top and the oil is produced from the bottom. This work investigated the influence of the gas injection rate on oil production. The experiments were history matched using the commercial numerical simulator GEM from CMG.
The experimental results showed good oil recovery performance with recovery factor as high as 40 per cent of OOIP, and it was observed that this value increases when higher gas rates are used. The numerical simulator has some limitations but provided a good history match with the results of the experiments.
This paper proves the efficiency of the CO2 injection in NFR and also presents a new procedure for experimental modeling of fractured systems.
The Mangala field in the state of Rajasthan of western India was the first major oil discovery in the Barmer basin and is the largest discovered oil field in the basin. It contains paraffinic oil with average viscosity of ~15 cp and wax appearance temperature only about 5°C lower than reservoir temperature of 65°C. The initial development plan was a hot waterflood to prevent any in situ wax deposition; recently, though chemical EOR methods have started to play an important role in the development of the field.
A polymer flood pilot was successfully conducted in the field. It was followed by an ASP pilot trial which used the same set of wells. Unlike the polymer pilot, ASP injection was confined to a single continuous sand to reduce interference with nearby wells and to reduce the uncertainty in interpretation of pilot results. A combination of a high molecular weight branched alcohol PO-EO sulfate and a high carbon number sulfonate was selected for the ASP formulation. The selected surfactants functioned well in the desired salinity range and were stable in an aqueous solution up to half a percent higher alkali concentration than the optimal concentration.
The pilot facilities needed to meet a number of challenges arising from using neat surfactants-mainly handling of viscous/gelling material, maintaining accurate dosing rates, maintaining the right ratio of two surfactants, and maintaining stability of the sulfate itself. These challenges were surmounted in the pilot by using a blended surfactant solution, diluted with water, with activity of 24%.
ASP injection led to mobilization of significant volume of oil in the confined 5-spot pattern. The oil-cut of the central producer increased from 10% to 80%. The oil production rate showed almost an eight fold increase from 50 bopd to nearly 400 bopd. The estimated incremental recovery over polymer flooding is nearly 20% of the pilot STOIIP. Later in the pilot project the expected increase in water-cut was accompanied with the production of the injected chemicals along with rise in the pH of the produced water, indicating that favourable mobility was maintained during ASP injection. Some production challenges were encountered—most notably the failure of the producer's electrical submersible pump (ESP); this required the producer to be put on jet pump intermittently when the ESP was not functioning. The saturation observation wells located within the pattern area showed significant desaturation of oil. Sponge cores acquired after the pilot showed very low remaining oil saturation in the flooded sections. The paper will discuss the pilot operations, monitoring and quality control, the pilot results, and lessons learnt.