Passive inflow control devices (ICD) are being rapidly adopted in horizontal production wells particularly when there is a high probability of produced water or gas in a heterogeneous reservoir in the early life of a well. The justification, application, installation and the flow physics of ICDs available to the industry are well documented in the literature [1-3]. However, there are limited case studies that discuss the production and reservoir performance, to investigate their longer term impact supported with actual production data. The De Ruyter Field, which started production in September 2006, has been completed with passive ICDs in combination with zonal isolation in two horizontal wells in the undersaturated western fault block. This paper will describe how ICDs increased recovery compared to stand alone screens, by controlling water production and promoting inflow from lower productivity zones thus extending the life of the De Ruyter Field . This paper will also discuss the use of actual production and PLT data to history match a dynamic simulation model. The ICDs allowed the operator to commercialize an offshore development by delaying and controlling water production in a heterogeneous reservoir, thereby increasing recovery and extending the field production life.
A simulation study was conducted to examine the effects of changing the landing position of the short production-tubing string relative to the heel of a steam-assisted gravity-drainage (SAGD) production well. A homogeneous discretized wellbore model with the riser section was used in this study. Generally, a reservoir is modeled independently of the wellbore. However, this study models the reservoir and wellbore simultaneously in order to understand their interactions. SAGD performance is affected by many interrelated parameters; however, this paper is focused only on the effects of changing the short production-tubing string relative to the heel of the well.
This paper outlines two independent case studies:
The results for this study will assist SAGD producers in re-evaluating the position of the short production-tubing string and find the most economical position for this string. This paper creates the foundation for further simulation efforts to incorporate a discretized model with the build section coupled to the reservoir. This will allow production engineers to optimize bitumen production by simultaneously simulating the reservoir and wellbore strings together. However, it must be kept in mind that the sensitivity study outlined in this paper only includes different placements of the short production-tubing string while keeping all other parameters constant. More work should be done in order to evaluate the interrelated effects of changing the location of the short production-tubing string with other wellbore and reservoir parameters.
Pressure drop along the horizontal wells and between the injector and producer could have a significant impact on SAGD process performance. However, this issue is poorly understood due to difficulties in simulating pressure drop. This paper presents the results of a numerical study on the topic.
When pressure drop between the injector and producer exists, the downhole vapour production rate must be increased significantly. Without adequate vapour production, the oil production rate is lower and SOR is higher. Increasing the vapour production rate may affect pad facility design as more vapour handling capacity is required under these conditions.
On the other hand, pressure drop inside the injection well may also alter steam distribution. However, the impact on oil production is limited as steam can move relatively easily inside the steam chamber. In the present case, oil production is reduced by approximately 5% when a pressure gradient along the injection well is considered.
This paper investigates the feasibility of bitumen production using SAGD technology with a longer wellbore. A longer wellbore can be used to exploit a greater volume of the reservoir with a single wellpair as opposed to multiple wells; thus, decreasing pad and drilling costs.
The major concern in using a longer wellbore from a reservoir engineering point of view is the potentially non-uniform steam chamber growth over the whole well length due to pressure drop in the horizontal well. Reservoir simulation was performed using Computer Modelling Group's STARS ™?simulator and the QFlow thermal wellbore simulator to address the issue. The pressure drop inside the wellbore was calculated using QFlow. Reservoir simulations were performed using STARS. A sectioned model was constructed, dividing the whole length of the horizontal wellbore into multiple sections, each with its own pressure restriction to match the pressure drop obtained from QFlow. The results showed that with a sufficiently large wellbore size that resulted in a sufficiently low pressure drop, one longer well performed as well as two shorter wells. When a smaller wellbore size was used, production from a longer well was significantly impeded due to the large pressure drop.
Most SAGD projects require about one to two years for ramp-up. Over this period of time, oil rate will be below peak oil rate and SOR will be higher than long-term steady-state SOR. This paper discusses the effect of steam injection pressure on SAGD ramp-up time, the associated geomechanical effects and optimization of the ramp-up phase of SAGD. Different steam injection pressures induce different reservoir geomechanical behaviour in oil sands. Higher steam injection pressure is capable of inducing more favourable reservoir geomechanical effects (such as shear dilation and isotropic unloading), improving the reservoir permeability, and subsequently, benefiting the long-term SAGD operation. This paper indicates that the ramp-up time can be reduced due to the favourable geomechanical effects. A coupled reservoir geomechanical simulation technique was applied for this investigation. In addition, cap rock integrity concerns when applying high injection pressure are also addressed. It is recommended that during or following the ramp-up phase, the injection pressure be lowered to a safe operating pressure to ensure cap rock integrity. The effects of low and high steam chamber pressures on SAGD oil rate are also discussed.
A smooth start-up is crucial to the successful operation of a SAGD process. A simulation study was conducted to analyze the start-up or circulation period of SAGD well pairs. A coupled reservoir/wellbore model was developed and used to history match field data obtained from wells with extensive instrumentation at Petro-Canada's MacKay River development. The history matched model was then used to conduct a sensitivity study on some of the parameters that affect the circulation of a well pair.
First, the steam-to-toe time was examined for the two typical wellbore completions that Petro-Canada employs at MacKay River. Various flow rates were tested for the two completions to see how the steam injection rate affected the steam-to-toe time.
Next, the circulation pressure along with the injector/producer pressure gradient was investigated. Various pressure gradients were applied between the injector and producer to examine the effects on the circulation duration and the formation of steam coning.
Finally, the distance between the injector and producer was studied. The purpose was to explore the effect of the vertical separation between the injector and producer wells on conversion time.
A simulation study was carried out to examine the effects of changing the landing position of the short production tubing string relative to the heel of a SAGD production well. A homogeneous discretized wellbore model with the riser section was used in this study. Generally, a reservoir is modeled independent of the wellbore. However, this study models the reservoir and wellbore simultaneously to understand the interactions between them.
This paper outlines two independent case studies, which are outlined below:
1. The first study involved shortening the short production tubing string relative to the heel of the well. It was found that as the short tubing string was pulled back from the heel of the well the bitumen production rate decreased, and the amount of steam produced through the short production tubing string increased.
2. The second case study outlines the impact of extending the short production tubing string past the heel of the well on bitumen production and SOR. From this case study, it was found that as the short production tubing string was pushed past the heel of the well, the bitumen production rate stayed the same, but the steam injection rate decreased which consequently decreased the SOR. It was also observed that a lower pressure differential between the injector and producer well was established when the short production tubing string was extended.
The results for this study will assist SAGD producers to re-evaluate the position of the short production tubing string, and find the most economical position for this string. This paper creates the foundation for further simulation efforts to incorporate a discretized model with the build section coupled to the reservoir. This will allow production engineers to optimize bitumen production by simultaneously simulating the reservoir and wellbore strings together.
Traditional oil sands mining operations have used deterministic techniques to create a single resource model for mine planning. Stochastic modeling, commonly used for in situ oil sands evaluation, provides more realistic geology and allows for multiple realizations, which mining operations can use to assess the variability of recoverable bitumen volume estimates and develop mine plans accordingly. The existence of multiple realizations makes it possible to measure uncertainty, but eventually detailed mine planning will proceed based on a single realization. This paper discusses the processes of stochastic modeling and of determining the appropriate single realization for mine planning as applied to an oil sands mine currently in the planning stage (Fort Hills).
Geological models for mining operations have less uncertainty than models for in situ operations due to the much closer drill hole spacing and the better understood recovery process for mining, but the level of uncertainty is not zero. The same techniques that are currently being used to assess uncertainty for in situ oil sands leases can be applied to mining leases to quantify uncertainty for mine planning. In the case of Fort Hills, 100 realizations of ore grade were created using conditional simulation. Ranking solely by total bitumen in place was insufficient, so a new measure of heterogeneity related to vertical ore-waste changes was developed and is discussed in this paper. These two measures were combined to rank the realizations and to select mid, high, and low cases. The combined ranking resulted in ordering the realizations in a way that correlated with other measures of recoverable resource volumes, and lends support to the choice of the "mid?? model (centrally located in the ranking) for use in detailed mine planning.
The conditional simulation for Fort Hills marks the first time that stochastic modeling has been applied to full field modeling and then used for mine planning in an oil sands mine. The ranking method, including the methodology for assessing mining heterogeneity, is new and heretofore unpublished, and is the ultimate topic for discussion in this paper.
Snubbing involves the running of tubing and related completion equipment into a well while pressure is present at the wellhead. This operation requires the use of specialized equipment that provides control of well pressure and associated fluids at all times, and enables the movement of tubulars and equipment into and out of the well.
Petro-Canada chose to create their own snubbing guidelines, and share them with industry, because of situations being encountered that were not adequately described in published recommendations and regulations. The Petro-Canada Snubbing Guidelines are intended to compliment, rather than replace, Industry Recommended Practices on snubbing.
Petro-Canada's Snubbing Guidelines contain the following information:
1. Written guidelines, providing information on snubbing and well control equipment, safety requirements, snubbing procedures, and contingent operations.
2. A procedure for preventing downhole explosions when pulling plugs.
3. Pipe buckling calculations, as related to wellbore pressure.
4. Allowable tensile loads, as a function of internal and external pressures.
5. A snubbing operations checklist.
This paper addresses i) avoiding downhole explosions, ii) preventing pipe buckling in pipe-light situations, and iii) allowable tensile loads as a function of internal and external pressures.