In May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 103m3 (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 103m3 (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible.
A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations.
Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells.
The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.
This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough.
Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells.
Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection.
Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.
Castro, Ruben Hernan (ECOPETROL, S.A.) | Maya, Gustavo Adolfo (Ecopetrol SA) | Sandoval, Jorge (Ecopetrol SA) | Leon, Juan Manuel (Ecopetrol SA) | Zapata, Jose Francisco (Ecopetrol SA) | Lobo, Adriano (Ecopetrol SA) | Villadiego, Darwin Oswaldo (ECOPETROL, S.A.) | Perdomo, Luis Carlos (ECOPETROL, S.A.) | Cabrera, Fernando Ariel (TIORCO, Inc.) | Izadi, Mehdi (TIORCO, Inc.) | Romero, Jorge Luis (TIORCO Inc) | Norman, Charles (TIORCO, Inc.) | Manrique, Eduardo Jose (TIORCO, Inc.)
Dina Cretaceous Field is located in the Upper Magdalena Valley (UMV) Basin, Colombia. Dina Field operated by ECOPETROL S.A. (discovered, 1969) started peripheral water in 1985. Based on high water cuts (96%) and recovery factors of 32%, comprehensive enhanced oil recovery (EOR), screening evaluation began late 2009, identified Colloidal Dispersion Gel (CDG) as an optimum EOR method for the field.
This paper summarizes Dina CDG project from the laboratory to the field evaluation. Laboratory studies include basic fluid/fluid evaluation, static adsorption, CDG formulations, slimtube, and coreflood tests. Pilot area selection was based on a comprehensive reservoir and injection/production data analysis, water management, well integrity, among other factors. Pilot design was based on detailed numerical simulations using sector and full field models. CDG pilot design also considered water handling limitations and potential injectivity constraints due to the narrow margin of maximum injection and reservoir pressures, combined with low reservoir permeability (50 to 200 mD).
Peripheral CDG pilot included one injector and three producers. CDG injection began in June 2011 and as of September 2012, approximately 437,000 bbl of CDG have been injected (5% of pilot PV). CDG injection strategy considered a fix polymer concentration of 400 ppm and a variable polymer/crosslinker ratio ranging from 40:1 to 80:1; to control maximum injection pressure. Field results showed an important increase in oil recoveries (oil productivity up to 300%) and reduction of water cut decrease (10%). After 16 months, no polymer had been produced in offset producers. Main operating challenges experienced during the pilot project included; the improvement in water quality and its impact on CDG injectivity which will also be described.
This study provides guidance to successfully design, implement, and evaluate CDG pilot projects and other potential chemical EOR technologies in waterflooded reservoirs. Lessons learned during pilot testing contributed to defining pilot expansion strategies supported by an integrated decision-risk management approach.
Selecting the optimum combination of enhanced oil recovery (EOR) technologies is a critical activity during preparation of a successful business plan. This is usually accomplished by using protocols with technical parameters at reservoir formation levels from which candidates EOR technologies are screened and then
subject to investment and risk assessment evaluation for final decision by management.
The previous approach very often misses the effect of operational expenditures, wearing and failure related downtime and learning curve during pilot testing on oil recovery efficiency and EOR economics which is usually expressed in terms of net present value.
This paper proposes an alternate simplified approach using an acceptable representation of life cycle phases of natural and physical asset components functioning as a system of assets for a particular subject reservoir. We introduce a taxonomic solution to help in classifying candidates EOR technologies. Four major functional indices are used for handling uncertainties and risks using data from analogs for defined scenarios in the subject reservoir: 1-Accesability) Footprint effects for constructing and operating physical assets (wells and surface infrastructure), 2- Contactability) Volume of resources contacted from a surface
location, 3-Produceability) Volume of producible resources from drainage area to surface and 4- Effectiveness) Combined effect of availability, reliability, maintainability y and capability in efficiency of oil recovery.
The four major indices are cross referenced with life cycle cost (LCC) and estimated ultimate recovery (EUR) using Hubbert peak oil theory and the Petroleum Resources Management System classification for resources and reserves. Uncertainties and risks are modeled with Monte Carlo simulation (MCS) or
Systems Dynamics (SD) depending on the complexity of the system of assets.
We present examples using synthetic data to illustrate the method.
This approach is worth using during EOR project definition and planning as an alternate to complex data hungry methods.
Most of the world's oil is found in a small number of ‘petroleum systems'. A petroleum system is an area where oil or gas was created in a single ‘pod' of source rock which has migrated upwards and become trapped in a number of oil and gas fields or assets. Not only is oil concentrated mainly in very few provinces
and petroleum systems within these provinces, but within a given petroleum system, it is concentrated inside very few fields (1).
Therefore it is a fact that the oil and gas industry deals with the management of a finite, depletable or exhaustible resource, i.e., hydrocarbon resources.
The production of any hydrocarbon resources from a field or asset has a gradual increase (development phase) reaching a maximum output (peak), then a plateau and a decline (maturity) when the output will fall irreversibly down to an economic limit where the decision of abandonment needs to be addressed. Many fields combine together, placing a small number of large fields near the beginning and a large number of small fields at the end produce something like a bell curve as shown in Figure 1. This bell curve is also called Hubbert Peak Curve after the geophysicist M.King Hubbert who predicted in 1956 (2) (3) that the oil production for the lower 48 states of USA would peak between 1965 and 1970.
Hubbert recognized that the depletion of any finite resource starts with production at zero and that in the initial stages, the rate of oil production tends to increase exponentially with time. However, physical limits prevent production to increase at the same rate because finite resources cannot keep up the increasing production rate forever. At the end of the life cycle the total volume under the bell curve will be the ultimate recovery.
The magic of Hubbert´s approach was the use of a proxy model known as the logistic equation, developed by the Belgian statistician Pierre Verhulst which was an improvement over the Malthusian model (4). In 1982, Hubbert refers to the original Verhulst papers and goes through a complete derivation of the
mathematics involved in his model. The details and implications of the use of proxies for modeling management of finite resources is beyond the scope of this paper, however we address the issue from an economic perspective later in the paper. For now we can state that Hubbert Peak curve can be used to
empirically approximate the full cycle of the growth, peaking, and subsequent decline to zero of the production of a finite, nonrenewable resource and estimate ultimate recovery.
Advantages of CO2 in enhanced oil recovery for Iranian oil reservoirs offers a unique opportunity to boost incremental oil recovery and reducing emissions of greenhouse gas through geological sequestration. Moreover, because of the dominant role
of gravity force in gas injection process in fractured reservoirs, and also relatively low minimum miscibility pressure (MMP) of CO2, therefore, miscible CO2 injection with Gas Oil Gravity Drainage (GOGD) mechanism can be considered as an
efficient method in most carbonate reservoirs.
In this paper, different production strategies such as vertical and horizontal immiscible and miscible gas injection were applied to find the optimum EOR method in one of the under-saturated Iranian fractured reservoirs.
To aim this goal, a study with simulation approach was conducted while the effect of gravity drainage on recovery was investigated besides other mechanisms. A complete analysis of phase behavior, PVT properties of reservoir fluid and CO2
mixture was done. These data were applied in designing of the slim tube and full field simulation model. A fully compositional reservoir simulator was employed to understand the reservoir characteristics, also, verifying the suitability of CO2 injection.
Material balance analysis indicated the original oil in place (OOIP) is about 910 million STB with a relatively strong water support. The maximum oil production of 60,000 STB/D was assumed in all simulation cases. Reservoir simulation results
revealed that additional oil recovery could be obtained from this fractured reservoir by miscible gas injection, while gravity drainage was the main displacement mechanism. In case of vertical well production, the model predicted an increase in oil
recovery about 24 and 28% OOIP for immiscible and miscible CO2 injection respectively. Considering horizontal producers and gravity drainage as the dominant production mechanism, immiscible and miscible gas injection will enhance oil
production more than 28 and 36% OOIP respectively.
Enhanced Gas Recovery (EGR) is a way of producing residual gas in depleted gas reservoirs. CO2 injection is a promising method for EGR by increasing the reservoir pressure and also gas-gas displacement. The miscibility of injected CO2 and residual gas in place is an important factor in this process.
The objective of this work is to investigate the miscibility process of CO2 injection into gas reservoirs using a compositional and a black oil reservoir simulator. A synthetic simulation model is built for this process having injection and production wells. The effect of gas miscibility is studied for both simulators and the results are compared to find optimum miscibility parameters.
The simulation results show that compositional result is similar to the black oil run, when the miscibility factor in the later case is almost half of the complete miscible process. In case of no miscibility the extension front is very sharp while for the case of complete miscibility the CO2 front is more advanced toward production well with wider length of miscible zone.
The findings of this paper could be beneficial for further pilot and field case study for monitoring of the observation and abandonment wells. Also the method is helpful in using black oil simulator as an alternative, less working effort and same reliable for CO2 sequestration in comparison to a compositional simulator.
Wu, Shuhong (Research Inst Petr Expl/Dev) | Min, Han (Greatwall Drilling Company, CNPC) | Ma, Desheng (PetroChina ) | Wu, Yongbin (RIPED, PetroChina) | Yu, Qian (Daqing Oil Field, PetroChina Co. Ltd.) | Chunli, Yao (Daqing Oil Field, PetroChina Co. Ltd.) | Dehuang, Shen (PetroChina )
Steam flooding, one of commercial technologies widely used to develop heavy oil reservoir, has brought reservoir engineer's attention to improve performance of waterflooding, light oil reservoir and enhance its oil recovery. In Cy reservoir of Daqing
oil field, a steam flooding project is successfully going on to enhance the oil recovery after waterflooding. Cy reservoir is a typical low-permeability, light-oil reservoir with depth of 1000m, an average permeability around 8 md and a typical porosity
of 16%, oil viscosity of 16~95mpa.s.
Cy reservoir came into development in 1995 under waterflooding. However, waterflooding has suffered from low water injectivity, poor sweep, and poor injector-to-producer communication. Only 10% of oil in place has been produced during 10
years' waterflooding. In 2007, steam flooding was utilized to improve the performance and enhance the oil recovery. The steam flooding project shows promising results. The response to steam injection is prompt and significant. The injectivity is
doubled and productivity is almost tripled. The oil-steam-ratio is around 0.3. The incremental recovery is predicted to be over 10%.
The paper will firstly brief production history of waterlfooding. Secondly, the paper will detail steam injection and analyze its performance and influence factors.The paper will also discuss mechanisms, strategies as well as barriers and difficulties to
high recovery of steam flooding in such waterflooding, light oil, low permeable reservoir andl also detail reservoir engineering study, such as development manner, injection and production system, and its physical and numerical simulation. The steam flooding project shows us that steam injection has great potential in improving injection and production profiles, increasing productivity and enhancing oil recovery.
The "PF-A-I?? - an undersaturated oil reservoir located in Hungary- is more than 50 years old.
It was discovered in the late 1950' years and put in production in 1960. The reservoir produced by depletion, then by CO2 injection, by WAG injection, afterwards by water injection and finally by "depletion?? again.
The case study shows all production stages in detail - the most important data, what were the results of different type of injections, how saturations, pressure, recovery factor changed followed by the comparison of planned injection and production rates with facts by diagrams and maps.
It shows why the CO2 injection was more important than the experts thought and which type of injection was the most effective and gave the most extra oil.
Wang, Ruifeng (RIPED, PetroChina) | Wu, Xianghong (China Natl. Petroleum Corp.) | Yuan, Xintao (RIPED, PetroChina) | Wang, Li (RIPED, PetroChina) | Zhang, Xinzheng (RIPED, PetroChina) | Yi, Xiaoling (RIPED, PetroChina)
This paper demonstrates the first cyclic steam stimulation (CSS) pilot test in Sudan, which was applied in FNE shallow heavy oil reservoir. B reservoir of FNE field is a shallow, heavy oil reservoir with strong bottom water, burial depth is 520 m. Well tests have shown low oil rates under cold production, averaging at 50-150 BOPD. Denser well spacing will be required if under cold production, which will be quite cost consuming. CSS generally could yield enhanced oil for heavy oil reservoirs. Therefore CSS pilot test has been planned by approaches as follows: 1) investigation of global heavy oil fields with successful CSS histories to confirm applicability in FNE field; 2) Pilot well screening criteria establishment based on sedimentary and reservoir engineering analysis; 3) Perforation optimization to avoid rapid coning based on thermal simulation; 4) steam injection parameters optimization; 5) applicability of natural gas as cost-effective heating source.
CSS Pilot tests on two wells began in 2009. Convincible results have been monitored with well daily rates 3-4 times of cold production wells with low water cut. Another six CSS wells further came on stream from July. 2010, achieving similar positive results. Conclusions drawn from pilot test were as follows: 1) Optimized perforation contributed to low water cut; 2) steam injection density was optimized around 120 t/m; 3) Natural gas as heating source greatly reduce operating cost.
Heavy oil reserves are estimated to take 40% of Sudan's total reserves. Sudan is also abundant in natural gas reserves, therefore cost-effective CSS development strategy has wide applications for similar Sudanese and African fields.
Successful CSS pilot test in this paper highlighted CSS well screening criteria, perforation strategy, steam injection optimization and natural gas utilization, giving a cost-effective staircase for CSS pilot design and implementation.
Inflow Control Valve (ICV) have been used in the past to enhance performance of producing wells for unfavorable environments, such as non-uniform permeability and pressure variation along the well sections. Nowadays, since Enhanced Oil Recovery (EOR) technique has been advanced, the ICV is introduced to be installed in the injector well, with the aim to produce more oil from the reservoir. The key factor in the success of this project was the use of Petrel to simulate the injection sweep across the entire Alpha reservoir section. Nozzle type ICV is used to obtain a piston-like water injection profile, and thus to achieve the objective of increasing sweep efficiency to recover more oil, and decrease water breakthrough in high permeability zone, if connected to the producers. Firstly, the reservoir is analyzed to choose the best candidate of injection well. Then, the sector modeling is run at the region near the injection well. The sector modeling reduces the time required to run the ICV simulation study. After that, the Base Case is created with open hole injection well. The result of the run is recorded. Then, ICV is installed with the sensitivity studies on the different valve apertures. The results show that the installation of ICV improves the oil recovery by 2%. The optimal depletion strategy for major oil reservoir is pressure maintenance by water injection with ICV. The full field simulation shows that the water production is reduced by 20% for the full field. Therefore, it shows that intelligent completion concepts can be applied at injection well besides at production well. This paper presents an innovative completion technology, fine tuned by reservoir simulations, for balancing the water injection profile into various sand formations zones in an open-hole completed injector well, increasing sweep efficiency.|