Carbon dioxide injection has recently been considered as a promising method for enhanced oil recovery. The supercritical carbon dioxide is often miscible or nearly miscible with the oil under reservoir conditions, which facilitates high recovery. Underground injection of carbon dioxide is also of a significant ecological advantage, and utilization of CO2 results in a noticeable reduction of the taxation of the petroleum companies. On the other hand, application of carbon dioxide under conditions of the North Sea petroleum reservoirs for enhanced oil recovery (EOR) is hindered by multiple practical problems: availability of the CO2 sources, logistics of the delivery offshore, corrosion resistivity of the installations, and other. Previous studies of CO2 EOR for the reservoirs of the North Sea region, including core-flooding experiments and reservoir simulations, indicate that the deployment of CO2-EOR can significantly enhance the recovery of hydrocarbons. However, CO2 must be generated from anthropogenic sources, which affects the feasibility of the projects.
The current study evaluates the potential of a CO2-EOR project under the conditions of a specific petroleum reservoir of the Danish sector North Sea. Geological characteristics of the reservoir and the detailed oil properties lie in the ground of the study. The minimum miscibility pressures between CO2 and the reservoir oil are evaluated with the help of the in-house software (SPECS 5.70) and the commercial reservoir simulator (ECLIPSE 300). The results are verified in the slimtube simulations. The effect of the different oil characterizations and its lumping into the different numbers of components is investigated. The oil is found to be miscible with the carbon dioxide under reservoir conditions.
Several injection scenarios have been tested on the 2-D and 3-D reservoir models. Waterflooding was compared to injection of carbon dioxide, as well as water-alternate gas injection. An optimal scenario with regard to water-gas ratio under WAG was selected for further studies.
Finally, a cash flow model by Monte Carlo simulations and a sensitivity analysis on the impact of oil and CO2 price and discount rate, certify the feasibility and attractiveness of a CO2-EOR project in the West Flank of the Dan field.
Wang, Yang (China University of Petroleum – Beijing and Pennsylvania State University) | Cheng, Shiqing (China University of Petroleum – Beijing) | Zhang, Kaidi (Lusheng Petroleum Development Co., Ltd, SINOPEC Shengli Oilfield Company) | Xu, Jianchun (China University of Petroleum – East China) | Qin, Jiazheng (China University of Petroleum – Beijing) | He, Youwei (China University of Petroleum – Beijing and Texas A&M University) | Luo, Le (China University of Petroleum – Beijing) | Yu, Haiyang (China University of Petroleum – Beijing)
Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors.
The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot.
Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.
This paper serves to provide a technical overview of the Real-Time Drilling (RTD) analytics system currently developed and deployed. It also serves to share practices used in managing the RTD analytics project which have resulted in the efficient delivery of work products. By employing the novel and agile development approach on the RTD project, the design to production time has been faster and has cost much less compared to a more traditional multi-year effort and cost intensive RTD development project. Within three months, for proof of concept (PoC) purpose, an RTD analytics system with two analytics modules was built from scratch and placed online in production. This real-time decision-support tool has been fully accepted by the operations team and has become a powerful tool for daily well operations. After eleven months as this paper was drafted, this system has four analytic modules online for production and three analytic modules under development; it is expected that more new modules will be added to the system on a regular basis.
He, Youwei (China University of Petroleum, Beijing) | Cheng, Shiqing (China University of Petroleum, Beijing) | Li, Lei (China University of Petroleum, Beijing) | Mu, Guoquan (Research Institute of Petroleum Exploration and Development, Changqing Oilfield) | Zhang, Tiantian (The University of Texas at Austin) | Xu, Hainan (China University of Petroleum, Beijing) | Qin, Jiazheng (China University of Petroleum, Beijing) | Yu, Haiyang (China University of Petroleum, Beijing)
Because of the effect of reservoir heterogeneity and fractures in low-permeability reservoirs, effective characterization of waterflood direction and front has become a challenging issue under high-water-cut condition. To achieve better understanding of such a complex problem, a work flow, containing statistical and numerical techniques, is developed to characterize waterflood direction and front distribution in Changqing oilfield by using both flow rates and bottomhole-pressure (BHP) data. The work flow includes four steps: First, dynamic analysis is used to qualitatively investigate the relationships between injector and producers; then, the constraint multiple-linear-regressions (MLR) method is applied to calculate the interwell-connectivity coefficients, which was used to quantitatively describe the waterflood direction by production and injection rates. On the basis of the results of the two former steps, we can adopt numerical well testing as our third step to deal with flow rates and BHP data to characterize the waterflood direction and front. Finally, the streamline method is used to simulate the waterflood front and high-permeability channel distribution on the basis of the outcome of the three preceding techniques.
Compared with individual methods, the proposed work flow can offer more perspectives and ways to make a comprehensive and deep investigation of the waterflood reservoir. The results obtained by this work flow enable proactive and better waterflood management in the Well Group W16 in Changqing oil field; namely, the water cut of producers decreases, meanwhile the oil production increases by nearly 40% referring to the field data in 2015. With the help of the information obtained by this work flow, operators could make more-reasonable decisions on waterflood management such as well-pattern optimization and injection–production parameters adjustment.
Ghasemi, M. (Petrostreamz) | Astutik, W. (Petrostreamz) | Alavian, S. (Pera AS) | Whitson, C. H. (Pera AS) | Sigalas, L. (Geological Survey of Denmark and Greenland) | Olsen, D. (Geological Survey of Denmark and Greenland) | Suicmez, V. S. (Maersk Oil and Gas A/S)
This paper presents the oil recovery mechanism by tertiary-CO2 flooding in a composite fractured chalk core. We perform two different core flooding experiments at reservoir conditions. We evaluate the efficiency of tertiary-CO2 flooding in different conditions, taking into account the effect of capillary continuity, water composition, and the heterogeneity.
The composite core consists of six core plugs placed vertically in-line in the core holder with total length of 45 cm and average diameter of 3.74 cm. We use qualitative filter paper between each core plug to reserve the capillary continuity at reservoir conditions (258 bara and 110 °C). The "fracture" is represented by a centralized axial hole with a diameter of 0.6 cm. In all experiments, the composite fractured core is initially saturated with North Sea Chalk Field (NSCF) stock tank oil (STO) and synthetic connate water. Once the reservoir conditions are established, brine is injected from the bottom of the fracture and the oil is produced from the top. We stop WF after no more oil is being produced. CO2 is then injected from the top of the fracture and the oil is produced from the bottom.
Experiments Exp-1C and Exp-2C utilize Sigerslev outcrop chalk cores. To account for the effect of initial water composition during WF, system is initially saturated with synthetic sea water with considerable amount of sulfate instead of formation water in Exp-1C. Whereas, we employ synthetic formation water with zero sulfate content in Exp-2C.
The results of experimental work are reproduced via validated compositional reservoir simulator with a tuned equation of state (EOS). We develop an automated history matching algorithm to match the experimental data of WF and CF periods.
We observe a major impact of the initial water composition that results in strong- to moderate- spontaneous imbibition during WF period. Moreover, both experiments and simulations show that the tertiary CO2 recovery is significantly affected by the water saturation in the core after the secondary WF. We conduct a sensitivity analysis to study different CO2 injection scenarios such as in a single block, in a composite core with capillary continuity, and in a composite core with horizontal fractures in between. The results show the oil recovery during tertiary-CO2 flooding is barely affected by the degree of the capillary contacts between the chalk matrixes. Moreover, it is found that the mass transport during CF is mainly covered by diffusion rather than the convective flux or viscous forces.
We build a modeling framework that accounts for proper modeling of imbibition and diffusion dominated processes in a composite chalk system at reservoir conditions.
ABSTRACTPipelines for transferring pressurized seawater constitute a significant part of the network for enhancing oil recovery in many offshore oilfields. To maintain the integrity of the system it is important to mitigate corrosion in the pipeline, or consequently corrosion may cause the operational pressure to be lowered or, in a worst-case scenario, a pipeline failure. Water treatment is essential to mitigate corrosion, although the potential for microbiologically influenced corrosion (MIC) in injection water pipelines is assumed to be lower compared to oil or multiphase pipelines where nutrients are abundant and a higher temperature facilitates microbiological growth.Presence and activity of MIC-causing microorganisms were investigated in a 16” diameter and 9.6 km long injection water pipeline from the platforms Dan FF to Halfdan A and further to Halfdan B. Nitrate was added to the water and sampling of pigging debris from the pipeline showed that both sulfate-reducing bacteria (SRB), nitrate-utilizing bacteria, and methanogens were present in significant numbers of 105 - 106 cells/g. Enrichment cultures of SRB showed that exponential growth occurred within 22 hours at 20 °C. The metabolic parameters will be implemented in a model to quantify more accurate determination of the MIC risk in injection water pipelines.INTRODUCTIONMicrobiological diversity and growth has a significant impact on the integrity and maintenance of the production systems in oil fields. Microbiologically influenced corrosion (MIC) plays a major role in particular pipelines where the anoxic conditions can facilitate growth of microorganisms that causes direct or indirect oxidation of carbon steel. The major microbiological players in this respect are sulfate-reducing bacteria (SRB), sulfate-reducing archaea (SRA), and methanogens.The introduction of microbiological molecular methods as a tool for monitoring SRB, SRA and methanogens has improved prediction of MIC, thereby mitigation strategies, and has further increased awareness of the key microorganisms that cause MIC corrosion1. Enumeration of these microorganisms can be accurately determined by quantitative polymerase chain reaction (qPCR) and the metabolic activity can be measured by reverse transcriptase followed by qPCR (RT-qPCR). Quantification of numbers and activity have been included in a model - the Maersk Oil MIC model - for predicting potential pit generation rate and time for MIC corrosion to develop in environments with a temperature range of 25 to 85 °C2. The output of the model is helpful to determine actions such as pigging effort, biocide application, corrosion investigations, and inspection activities.
There is little doubt that the success and reliability of frac-pack completions in the Gulf of Mexico has become the yard-stick by which Gulf of Mexico sand control completions are currently measured. Simultaneously, StressCage has become common practice as a method to overcome challenges drilling through depleted zones, in order to cope with complex mud-window constraints for new developments and infill wells. The success of these drilling and completion approaches and their rapid widespread application has resulted in ever more depletion. This has potentially created a vicious circle in terms of drilling the well to desired depth vs. the ability to install a low-skin frac-pack completion.
While these two techniques in isolation represent uniquely optimal solutions to their individual challenges, there is growing evidence that their application within the same wellbore has the potential to create conflicting ideals. The StressCage application is associated with the plugging of small fractures which have been induced in the wellbore wall, thereby increasing the effective fracture gradient, which allows for the drilling of substantial depletion. However, the presence of a range of widely distributed particle sizes in the mud system, as well as increased general solids loading, may result in deep and invasive plugging of the permeable formations and any smaller fractures within the same open-hole sections. When these plugged formations are then the target for subsequent fracturing operations, there is a significant potential to create near wellbore problems that complicate or bring into question the ability to install a frac-pack completion.
This paper will provide a number of examples of the application of StressCage, where resulting frac operations appear to have been hampered or complicated by the use of the StressCage approach and/or associated mud conditions. These examples will provide some evidence of such interactions but, more importantly, demonstrate the contradiction that these two techniques potentially represent. The paper will also outline a scenario resulting from a sand-control lower completion assembly in place, in a new borehole drilled with StressCage method, that could be resistant to any form of frac breakdown (or simple mechanical intervention), and, thereby, compromise the frac and well completion itself.
In addition to the case histories, the paper will outline various engineering approaches that should be considered, including geo-mechanical analysis of well placement, identification of near wellbore issues prior to and during the fracturing operations, careful management of stress caged solids makeup, mud management and frac-pack design in order to avoid or overcome such challenges. All of this helps ensure that we do not create the paradox of being able to drill through the undrillable but then creating the unfraccable as a result.
Waterflood implementation accounts for more than half of the oil production worldwide. Despite the observations and extensive research from a large number of floods and thousands of simulation studies, managing waterfloods and Enhanced Oil Recovery (EOR) floods is still a technical challenge. A major contributor to this challenge are waterflood induced fractures (WIF). Managing waterfloods is a multivariable problem although WIF are one aspect, it is by no means the only controlling factor.
The best evidence that WIF are one of the main factors controlling flow in reservoirs is the insensitivity of injection pressure to injection rates. With our experience, in hundreds of waterfloods, we have frequently observed this phenomenon in the field data. If fluid flow depended on diffusive Darcy flow alone, we would expect higher injection rates with higher injection pressures. However, it is common to observed relatively constant injection pressures over a wide range of water injection rates. Rapid well communication and changes in water cuts that vary with injection rates also support an interpretation of high permeability induced fractures between injector and producer. In some reservoirs, interwell tracer data can be used to determine the influence of induced fracture features. The interwell tracers usually show very fast water movement.
Induced fractures in waterfloods and EOR projects can be caused by a number of mechanisms such as but not limited to, pressure depletion, changing pressure regimes, thermal effects, or plugging effects. These fractures can either be beneficial to the reservoir performance or effect performance negatively. Benefits include improved injectivity and increased throughput of the displacing fluid. Negative effects can come in the form of reduced volumetric sweep efficiency, impaired ultimate recovery or injected fluid losses out of zone.
Case studies, theory, and available literature from Western Canada will be reviewed in order to suggest and improve reservoir management strategies for waterfloods. We have completed hundreds of waterflood feasibility, waterflood management and EOR flood studies worldwide and continue to be amazed and humbled by the complexity that many waterfloods and EOR floods exhibit due to induced fracturing. WIF and EOR induced fractures (EIF) are common and should be analysed to optimize production. Growth of the WIF, response to waterflood with the presence of WIF, implication of WIF and reservoir management are the main areas which will be addressed.