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.
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.
Polymer transport and preparation can present a key challenge in chemical EOR project implementation.
Hydrolyzed polyacrylamide in emulsion form presents some advantages, including an easier transportation and a simplification of the injection process. The trade off is a lower active concentration (~30% - 50%), which increases the volumes to be transported, as well as the presence of oil and emulsifiers, which may have unintended effects in the reservoir.
In this article, we compare two industrial and commercially-available polymers, one in powder form from the gel process, and the other in an inverse emulsion, with similar viscosifying power.
Properties of both polymers are investigated through rheological and screen factor measurements, filterability tests on bulk solutions, shear thickening behavior and resistance to shear degradation in porous medium. The likely origin of the observed differences is discussed in light of the two polymerization methods (bulk vs. emulsion) that lead to differences in polydispersity. Mobility reduction and residual resistance factor measurements during propagation tests at low velocity give some insight on the propagation of the stabilized oil droplets coming from the injected emulsion. Finally, oil recovery efficiency is investigated through secondary polymer injections on sandpacks. No significant difference was observed between the polymers in term of oil recovery or pressure behavior.
These results are relevant to oil companies planning polymer or surfactant-polymer pilots and considering the tradeoffs between emulsion and powder polymers.
The polymer pilot project performed in the 8 TH reservoir of the Matzen field showed encouraging incremental oil production. To further improve the understanding of recovery effects resulting from polymer injection, an extension of the pilot is planned by adding a second polymer injector.
Forecasting of the incremental oil production needs to take the uncertainty of the geological models and dynamic parameters into account. We propose a workflow which comprises a geological sensitivity and clustering step followed by a dynamic calibration step for decreasing the objective function to improve the reliability of a probabilistic forecast of the incremental oil recovery.
For the geological sensitivity, hundreds of geological realizations were generated taking the uncertainty in the correlation of the sand and shale layers, logs, cores and geological facies into account. The simulated tracer response was used as dissimilarity distance to classify the geological realizations. Clustering was then applied to select 70 representative realizations (centroids) from a total of 800 to use in the full-physics dynamic simulation.
In the dynamic simulation, an objective function comprising liquid rate and tracer concentration of the back-produced fluids was introduced.
To further improve the calibration, the P50 value of incremental oil production as derived from simulation was compared with the incremental oil production determined from Decline Curve Analysis from the wells surrounding the polymer injection well. The mismatch between the P50 and the Decline Curve Analysis was improved by adjusting polymer viscosity.
The calibrated models were then used to for a probabilistic forecast of incremental oil due to an additional polymer injector and to estimate the expected polymer concentration at the producing wells.
Many offshore heavy oil reservoirs underlain by large aquifer are developed through cold production method: horizontal wells, with water coning/cresting being a major concern. Inflow Control Devices (ICDs) are often used to delay the water breakthrough by balancing the well inflow along the well section. However, ICDs have difficulties to mitigate the water coning/cresting after water breakthrough, leading to water bypass oil, premature well abandonment and low oil recovery. In this study, we propose the use of a dual completion technology, Bilateral Water Sink (BWS), assisted with ICDs to mitigate water coning/cresting in high water cut wells, therefore improving oil recovery for offshore heavy oil underlain by large aquifer.
To investigate the reservoir performance under this new production technique, a series of experiments were conducted in a scaled Hele-Shaw model, similar to a cross-section of horizontal wells. Identical flow behavior at each cross-section perpendicular to the well axis were assumed. The experiments resemble to the situation in which the ICDs have been successfully implemented to provide a uniform flow along the entire well section. The oil recovery, water cut and reservoir pressure were measured in each runs to quantify the effects of BWS wells on water coning/cresting mitigation and improving oil recovery.
The experimental results show that while ICDs mitigate the non-uniform production profile along the horizontal well section, BWS wells mitigate the water coning/cresting by dynamically modifying the pressure distribution in the reservoir. Experimental results also verify that the previously derived theoretical rates in BWS can efficiently suppress the water coning/cresting after water breakthrough. The quantitative and qualitative results demonstrate that BWS could reduce the water cut from over 95% in high water cut horizontal wells to less than 40 % and improve the heavy oil recovery about 4-6 times compared with that of conventional horizontal wells.
Those findings provide a new insight into offshore heavy oil production mechanism. Because of BWS's ability of converting an original bottom water drive system to a more effective edge water drive system, low water cut and high oil recovery can be achieved by utilizing the reservoir energy without using of heat.
Al Ayesh, A. H. (Department of Geoscience and Engineering, Delft University of Technology) | Salazar, R. (Department of Geoscience and Engineering, Delft University of Technology) | Farajzadeh, R. | Vincent-Bonnieu, S. | Rossen, W. R.
Foam can divert flow from higherto lower-permeability layers and thereby improve vertical conformance in gas-injection enhanced oil recovery. Recently,
The effectiveness of diversion varies greatly with injection method. In a SAG (surfactant-alternating-gas) process, diversion of the first slug of gas depends on foam behavior at very high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This of course favors diversion away from high-permeability layers that receive a large surfactant slug, but there is an optimum surfactant slug size: too little surfactant and diversion from high-permeability layers is not effective; too much and mobility is reduced in low-permeability layers, too. For a SAG process, it is very important to determine if foam collapses completely at irreducible water saturation.
In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with time of injection. Injectivity is extremely poor with foam injection, but is not necessarily worse than waterflood in some effective SAG foam processes
Yeganeh, Mohsen (ExxonMobil Research and Engineering Co.) | Hegner, Jessica (ExxonMobil Research and Engineering Co.) | Lewandowski, Eric (ExxonMobil Research and Engineering Co.) | Mohan, Aruna (ExxonMobil Research and Engineering Co.) | Lake, Larry W. (The University of Texas at Austin) | Cherney, Dan (ExxonMobil Research and Engineering Co.) | Jusufi, Arben (ExxonMobil Research and Engineering Co.) | Jaishankar, Aditya (ExxonMobil Research and Engineering Co.)
A capillary desaturation curve (CDC) depicts the relationship between residual oil saturation, Sor, (i.e. oil left behind in a well-swept permeable medium) and capillary number. A CDC is one of the most fundamental curves of oil recovery as it reveals flow conditions required for good oil displacement in porous media. Despite the importance of this critical curve, the fundamentals describing the physics of a CDC are still incomplete.
We present a physical model to describe the capillary desaturation curve. The model balances the capillary pressure and applied viscous stresses caused by flow and takes advantage of contact angle hysteresis that occurs in porous media. It defines a critical oil ganglia length that depends inversely on capillary number and depends on porosity, permeability, and wettability. We have combined the critical oil ganglia expression and ganglia length distribution in porous media to arrive at an expression for the capillary desaturation curve. The model suggests that when a trapped oil ganglion is larger than the critical ganglia length, the applied pressure difference can mobilize the trapped oil ganglion. We describe the differences and similarities between our critical ganglia length expression and previously reported expressions. The model describing the relationship between residual oil saturation and capillary number was successfully verified with microfluidic experiments using various crude oils and displacing fluids. We have also demonstrated that the model applies to previously reported coreflood CDCs from sandstone and carbonate media. Extension of the model led to a single curve representation of variations in Sor with reduced pressure. This representation is independent of the chemistry of the displacing fluid.
The Medicine Hat Glauconitic C Pool is located partially inside the city limits of Medicine Hat, Alberta, Canada. This 15-18° API oil pool is under waterflood. Reservoir management strategies in the pool are limited by the reservoir quality, wellbore architecture and business environment. Surface land access due to the expanding Medicine Hat city limits and pre-existing wellbore orientations have constrained the waterflood pattern and infill drilling options. Current estimates indicate 21% of the oil in place will be recovered at the end of the waterflood.
The polymer flood pilot was started in 2012 with a goal to achieve 6% incremental recovery with a one year initial response time. The pilot's designed injection rate was 6,300 bbl/d (1000 m3/d) in 5 injectors, each representing different reservoir conditions and injection patterns. Following injection, pre-existing water channels and high permeability streaks resulted in rapid polymer breakthrough in as little as 48 hours in some cases.
To increase the efficiency of the polymer flood and reduce cycling polymerized water, a new approach to reservoir management had to be considered:
Each of the 5 patterns inside the pilot was monitored and managed individually, with a fit-for-purpose strategy in mind. Although 1 year to response was estimated, after four months, oil rates and oil cuts increased unexpectedly. However, after reaching peak production, the expected steep decline was observed. New reservoir management strategies were implemented in order to slow the decline and attempt to increase the incremental recovery from 6% to 10%: attempts to block water channels in the injectors, producer shut-ins and frequent injection target changes proved beneficial.
Each of the 5 patterns inside the pilot was monitored and managed individually, with a fit-for-purpose strategy in mind.
Although 1 year to response was estimated, after four months, oil rates and oil cuts increased unexpectedly. However, after reaching peak production, the expected steep decline was observed.
New reservoir management strategies were implemented in order to slow the decline and attempt to increase the incremental recovery from 6% to 10%: attempts to block water channels in the injectors, producer shut-ins and frequent injection target changes proved beneficial.
The polymer pilot has exceeded expectations to date.
This case study provides an outline of the changes that were made and the results that have been observed.
Erke, S. I. (Salym Petroleum Development) | Volokitin, Y. E. (Salym Petroleum Development) | Edelman, I. Y. (Salym Petroleum Development) | Karpan, V. M. (Salym Petroleum Development) | Nasralla, R. A. (Shell Global Solutions International) | Bondar, M. Y. (Salym Petroleum Development) | Mikhaylenko, E. E. (Salym Petroleum Development) | Evseeva, M. (Salym Petroleum Development)
Low-salinity waterflooding (LSF) has been recognized as an IOR/EOR technique for both green and brown fields in which the salinity of the injected water is lowered for particular reservoir properties to improve oil recovery. While providing lower or similar UTC's low salinity projects have the advantage of lower capital and operational costs as compared to some more expensive EOR alternatives.
This work describes LSF experiments, field-scale simulation results, and conceptual design of surface facilities for West Salym oil field. The field is located in West Siberia and is on stream since 2004. Conventional waterflooding was started in 2005 and current water cut is currently above 80% in the developed area of the field. To counter oil production decline a tertiary Alkaline-Surfactant-Polymer (ASP) flooding technique selected for mature waterflooded field parts and piloting of this technique is ongoing. Operationally simpler and more cost-effective LSF method is considered for implementation in the unflushed (green) areas of the field since it has been recognized that application of LSF in secondary mode results in better incremental oil recovery than LSF in tertiary mode.
The results of a comprehensive conceptual study performed to justify the LSF trial are presented in this paper. To generate production forecast for LSF in the isolated area at the outset of reservoir development the results of laboratory core tests executed at different salinities presented earlier (
Rodriguez, F. (PDVSA, IFP Energies nouvelles, Paris Diderot University) | Rousseau, D. (IFP Energies nouvelles) | Bekri, S. (IFP Energies nouvelles) | Hocine, S. (Solvay) | Degre, G. (Solvay) | Djabourov, M. (ESPCI Paris Tech) | Bejarano, C. A. (PDVSA)
Primary cold production for the extra-heavy oils (4–10°API) of La Faja Petrolifera del Orinoco (FPO), Venezuela, is currently a low percentage (<5%) of the OOIP. Chemical EOR (CEOR) studies are being accomplished in order to increase oil recovery in those thin-bedded reservoirs which host up to 35% of the OOIP, where thermal EOR methods are not convenient because of heat losses and environmental issues. Specifically, Surfactant-Polymer (SP) flooding is now considered as a feasible approach to achieve both mobility control and mobilization of residual oil in the FPO's target zones for CEOR.
The objectives of this experimental study were to identify some mechanisms in play when surfactant and polymer solutions are injected in cores to displace extra-heavy oil and to assess for the potential of SP flooding for one of the FPO's reservoirs. The tests reported were performed with a dead crude oil of 9°API and 4500 cP, and injection water salinity of 6.4 g/L with low hardness and at a temperature of 50°C. The SP formulation consisted of a standard high molecular weight HPAM at rather high concentration to achieve high viscosity and an alkaline-free surfactant formulation providing both low interfacial tension (IFT) and good compatibility with polymer even at high polymer concentration. When possible, oil saturation profiles were determined by CT-scan at the main steps of the experiments.
Conditions and methodologies to determine the relevant experimental parameters for high viscosity oil have firstly been developed. Then, a set of surfactant and polymer injection tests have been performed on Bentheimer outcrop cores. These tests demonstrated that injection of the SP formulation after a secondary polymer flood was able to achieve a significant reduction of the residual oil (ASo = 80% ROIP). Results of secondary injections of water (final oil saturation, Sofinal = 63%), surfactant solution (Sofinal = 39%) and SP formulation (Sofinal = 5%) have also shown that mobility control is of tremendous importance to achieve high recovery, even at the core-scale. The potential of the SP formulation has also been validated on unconsolidated reservoir rock material from the FPO (Sofinal = 8%). Relative permeabilities have also been determined to investigate the feasibility of an effective modeling of the impact of the surfactant on oil recovery without making any assumption of the local mechanisms in play. Future work will involve 3D reservoir simulation with physico-chemical parameters generated at the lab.