Rivero, Jose A. (Schlumberger Canada Limited) | Faskhoodi, Majid M. (Schlumberger Canada Limited) | Mukisa, Herman (Schlumberger Canada Limited) | Zaluski, Wade (Schlumberger Canada Limited) | Ali Lahmar, Hakima (Schlumberger Canada Limited) | Andjelkovic, Dragan (Schlumberger Canada Limited) | Xu, Cindy (Schlumberger Canada Limited) | Ibelegbu, Charles (Schlumberger Canada Limited) | Kadir, Hanatu (Schlumberger Canada Limited) | Sawchuk, William M. (Pulse Oil) | Pearson, Warren (Pulse Oil) | Ameuri, Raouf (Schlumberger Canada Limited) | Gurpinar, Omer (Schlumberger)
The Bigoray area of the Pembina field in western Alberta consists of approximately 50 naturally-fractured Nisku carbonate reefs. Production from the Bigoray Nisku D and E Pools started in 1978, and shortly after, water injection was initiated to maintain reservoir pressure as a secondary drive mechanism. By 2013, the pools had reached high water-cuts, making them uneconomical to produce. In 2017, a decision was made to reactivate the pools and initiate a solvent injection Enhanced Oil Recovery (EOR) project feasibility assessment.
A multi-disciplinary team was assembled to review and reinterpret all the geoscience data with modern methodologies to characterize the reservoirs and create new static model descriptions to be used in a dynamic model. Data from well logs, seismic, core measurements and image logs was integrated into a comprehensive and consistent model that could be used with certainty as a prediction tool.
A history-matching process was carried out by creating different realizations of the static model to honor well-to-well connectivity and water movement within the pools. The history-matching process was performed while ensuring that the model updates were global in nature and consistent with the geological understanding of the reservoirs.
The history-matched model was used to optimize the location of new producers and injectors based on remaining oil saturations and reservoir structure. Optimization of the EOR scheme involved testing a matrix of scenarios to investigate the effect of injection rates, solvent volumes as well as production pressures and voidage ratios. Additionally, in an effort to improve displacement efficiency, a large number of simulation runs were devoted to test and establish the most efficient locations for the well perforations in both the new injectors and producers.
This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are high.
Hydraulic fractures, whether created during a DFIT or larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure, which may be caused by near well friction or tortuosity but, may also result in more complex fractures in multiple planes.
Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional ISIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators.
Analysis of FFEP and ETFRs identified in the DFIT PTA analysis method combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
A distinct shift in wellbore fracture stimulation events has occurred within the Western Canadian Sedimentary Basin (WCSB) over the last 5 years. New designs, commonly referred to as "increased fracture intensity designs," are characterized by an increased number of fracture stages, decreased fracture spacing, and resulting increases in water and proppant required per stimulation. Existing technology applied in increased fracture intensity designs include: Open Hole Ball and Seat technology, Coil Activated sleeves, Plug and Perforating, as well as hybrid designs that combine several technologies. Increased fracture intensity designs have contributed to improved production rates and increased reserves and, as a result, have quickly become the preferred approach to hydraulic fracture stimulation of the reservoir. Promising hydraulic fracture designs and decreased spacing designs run the risk of being applied broadly without discrimination. Without proper retrospective or hindsight, there is a risk of over applying this new approach with false assurances of its success rates. It is therefore important to determine whether and at what point increasing fracture intensity generates diminishing returns. This paper provides 3 retrospective case studies within the regions of the greater Montney and Cardium formations where increased fracture intensity designs have led to decreased well production as well as decreased reserve allocation. We further examine the various components of increased fracture intensity designs to pinpoint areas where design optimization may have prevented these outcomes.
It will provide re ... Harkand has secured a USD 5 million contract from Swiber Offshore Mexico to perform saturation divin ... Two Bumi Armada subsidiary companies secured USD 300 million worth of contracts from ElectroGas for ... Amec Foster Wheeler has been awarded a contract by BP worth more than USD 73 million. Tam International, which provides inflatable and swellable packers for the oil and gas industry, has ... Sanchez Energy closed a deal with a subsidiary of Sanchez Production Partners to sell wellbore and a ... Penn West Petroleum has entered into a USD 321 million agreement with Freehold Royalties to sell an ... Bonterra Energy has acquired Cardium formation-focused assets in the Pembina area of Alberta, Canada ... Petrobras has sold its assets in Argentina’s Austral basin to Compañia General de Combustibles for U ... Pemex signed an agreement worth USD 1 billion with private equity firmFirst Reserve to jointly inves ... Gulfport Energy entered into an agreement to acquire Paloma Partners III for USD 300 million. Apache sold its 13% stake in the Wheatstone LNG terminal in Western Australia and 50% interest in th ... Shell Petroleum Development Company of Nigeria completed the sale of its 30% interest in Oil Mining ... Oil and gas safety company Secorp opened a new office in Hobbs, New Mexico. Bill Barrett Corp. has signed agreements with several undisclosed recipients for the sale of the maj ... Encana said it will sell its remaining 54% stake in PrairieSky Royalty via a USD-2.4-billion Cardinal Energy entered into an agreement with an unnamed seller to acquire assets whose total daily ... Petrobras has awarded a contract, worth USD 465 million over a period of 5 years, to Aker Oilfield S ... CGG received contracts for the 3D seismic acquisition of four surveys using its marine broadband tec ... IKM Subsea, a subsidiary of IKM Group, has been awarded a contract by Eni Indonesia to provide remot ... OneSubsea, Schlumberger, and Helix Energy Solutions signed a letter of intent to develop technologie ... Premier Hytemp has committed to opening a USD-20-million, 67,000-ft2 precision engineering facility ... Expro has constructed a new 20,000‑m2 facility in Macaé, Brazil.
Karpov, V. B. (RITEK) | Parshin, N. V. (Baker Hughes) | Sleptsov, D. I. | Moiseenko, A. A. | Ryazanov, A. A. | Golovatskiy, Y. A. | Petrashov, O. V. | Zhirov, A. V. | Kurelenkova, Y. V. | Ishimov, I. A. | Im, P. T.
The paper presents a study of field development optimization of the large tight oil field in West Siberia. The field is at an early development stage and is characterized by low permeability (less than 1 mD). It is developed by horizontal wells with multistage hydraulic fracturing.
Analysis of available information about the field revealed the potential to improve field development efficiency. Field development analysis and optimization were carried out based on the experience of development of similar Canadian reservoirs. Two large fields were selected as analogues: Bakken ViewField and Pembina Cardium. The data on these fields is publicly available. These fields are developed during a long period of time enabling operating companies to learn from experience and use new knowledge and data to optimize completions systems and development strategies as a whole. Therefore it is possible to not only analyze the current field development stage, but also trace the evolution of approaches and assess, what benefits can be obtained from making various changes to the applied technologies and field development strategy. The positive experience of development of the Canadian fields formed the basis for the field development optimization options.
A set of suggested project decisions will enable improvement in field development efficiency and, in case of confirming by pilot projects, can be recommended for full-field implementation in the considered field and in the analogue fields.
Verbitsky, Vladimir S. (Russian State University of Oil and Gas) | Igrevsky, Leonid V. (Russian State University of Oil and Gas) | Fedorov, Aleksei E. (Russian State University of Oil and Gas) | Goridko, Kirill A. (Russian State University of Oil and Gas) | Gubkin, Aleksei V. Dengaev (Russian State University of Oil and Gas)
One of the negative factors that reduce the oil industry efficiency in Russia is the problem of flaring of associated petroleum gas (APG) in flares. In this article complex issue of APG rational use is described as illustrated by one of hydrocarbon field of Russia. Tasks of research were chosen based on a detailed study of the field infrastructure and geological and physical characteristics of the design this formation. It was done to design SWAG technology with simultaneous gas withdrawal from the low pressure separation stages, respectively to reduce flaring APG.
Carbonate reservoirs, deposited in the Western Canadian Sedimentary Basin (WCSB), hold significant reserves of heavy crude oil that can be recovered by nonthermal processes. Solvent, gas, water, and water-alternating-gas (WAG) injections are the main methods for carbonate-heavy-oil recovery in the WCSB. Because of the fractured nature of carbonate formations, many advantages of these production methods are usually in contrast with their low recovery factor. Alternative processes are therefore needed to increase oil-sweep efficiency from carbonate reservoirs. Foam/polymer-enhanced-foam (PEF) injection has gained interest in conventional heavy-oil recovery in recent times. However, the oil-recovery process by foam, especially PEF, in conjunction with solvent injection is less understood in fractured heavy-oil-carbonate reservoirs. The challenge is to understand how the combination of surfactant, gas, and polymer allows us to better access the matrix and efficiently sweep the oil.
This study introduces a new approach to access the unrecovered heavy oil in fractured-carbonate reservoirs. Carbon dioxide (CO2) foam and CO2 PEF were used to decrease oil saturation after solvent injection, and their performance was compared with gas injection. A specially designed fractured micromodel was used to visualize the pore-scale phenomena during CO2-foam/PEF injection. In addition, the static bulk performances of CO2 foam/PEF were analyzed in the presence of heavy crude oil. A high-definition camera was used to capture high-quality images.
The results showed that in both static and dynamic studies the PEF had high stability. Unlike CO2 PEF, CO2 foam lamella broke much faster and resulted in the collapse of the foam during heavy-oil recovery after solvent flooding. It appeared that foam played a greater role than just gas-mobility control. Foam showed outstanding improvement in heavy-oil recovery over gas injection. The presence of foam bubbles was the main reason to improve heavy-oil-sweep efficiency in heterogeneous porous media. When the foam bubbles advanced through pore throats, the local capillary number increased enough to displace the emulsified oil. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. Overall, CO2 foam and PEF remarkably increased heavy-oil recovery after solvent injection into the fractured reservoir.
Petrophysical cutoffs of a hydrocarbon reservoir are among the key parameters to determine net pay, net-to-gross ratio (NTG), original hydrocarbon(s) in place (OHIP), and reserves estimation. Although the concept of cutoffs has been continuously used since the 1950s, so far there is no universal agreement on their definition and quantification methods. In the most commonly used procedure, log-derived shale-volume faction (Vsh), porosity (f), and water saturation (Sw) are tied back to experimentally measured rock permeability (k) values through a porosity/permeability crossplot. Then, limiting values of the three log-derived parameters are determined by use of fixed-permeability-cutoff values of 1 and 0.1 md for oil and gas reservoirs, respectively. Although these values, which are usually referred to as rule-of-thumb cutoffs, seem to be appropriate in some reservoirs, they can be misleading in most cases (e.g., tight gas and heavy oil). Furthermore, these fixed values have no mathematical basis because they were founded mainly on the basis of the experience in a number of typical reservoirs. Therefore, application of the rule-of-thumb cutoffs may cause significant errors in evaluation of petroleum reservoirs. This study focuses on technical and economic factors that have to be considered for delineating net pay. Mobility cutoff in this paper is founded on the flow equation (Darcy’s law) and combined with economic-profitability condition to quantify the cutoff individually in gas and oil reservoirs. Thereafter, a novel structured procedure is provided to integrate all core, petrophysical, and fluid data with the calculated mobility cutoff, thereby introducing a single permeability cutoff for the reservoir. One of the advantages of the new procedure over the traditional methodologies is that once a cutoff is determined for permeability, it does not require subsequent tying back to f, Vsh, and Sw to quantify the extra discrete cutoffs. In addition, the technique benefits from the use of permeability distribution within the reservoir in cutoff quantification. The procedure is simple, straightforward, general, and practically rationalized. Despite the previous works, it is noteworthy to mention that the newly developed approach is applicable to all types of hydrocarbon reservoirs, including typical reservoirs, tight oil and gas reservoirs, heavy-oil reservoirs, laminated- thin-bed reservoirs, and discrete stacked reservoirs, with wide ranges of rock and fluid properties. An example calculation is presented for application of the methodology in an Iranian carbonate reservoir. The example clearly illustrates how all available data from a reservoir should be integrated for appropriate determination of the permeability cutoff.
Prediction of extremely low permeability in tight reservoirs poses major challenges with traditional methods. Several studies have proposed nuclear magnetic resonance (NMR) permeability predictors, but these often give large errors when applied in tight formations. In this report, we describe a new method with NMR welllog measurements that decomposes the T2 spectrum into, at most, three Gaussian components. On the basis of parameters from the decomposition, we build a pore-size-based lithofacies model to predict whole-core horizontal permeability. With these parameters, we also modify the empirical Timur-Coates equation (TIM) to predict permeability. The NMR decomposition allows us to predict proportions of shale and silt. Applied to the tight Cardium formation, the parameters correlate strongly with core image and X-Ray-diffraction (XRD) results. In addition to Cardium data, we apply our approach to published data sets with good results, showing that the model gives accurate lithofacies-proportion estimates. To calibrate the model, Cardium probe permeameter data are used to identify facies permeabilities. Arithmetic-averaged permeability with the NMR-based model was calculated to compare with whole-core horizontal permeability. Monte Carlo analysis confirms the agreement between the model and core-permeability values. Our model provides a “bridge” to relate permeability between the probe scale (<1 cm laminations) and core size (>15 cm thin beds). Without the NMR well-log decomposition, Cardium TIM permeability predictions are in error by more than one order of magnitude in most intervals. The major challenge with the TIM model is obtaining an accurate T2 cutoff value. Compared with core measured bound-water saturations, the default 33 ms value is too large for our tight samples. Our NMR decomposition, however, shows good correlation with measured bound-water saturations. With several core samples and NMR parameters, we modified the TIM model and found that it provides very good permeability predictions.
In recent years, the tight Cardium sandstones of west central Alberta have observed significant new development with the application of multistage-fractured horizontal wells (MFHWs). This case study reviews the completion costs, economics, and production performance of 148 horizontal oil wells completed in the Pembina field halo areas (west and east), central Pembina, Willesden Green, and Garrington fields.
Production analysis was performed on all wells using the Duong decline-curve-analysis technique. This technique has been used successfully on tight multistage-fractured wells in other areas, and has proved successful at predicting long-term well performance and recoveries. Wells were chosen for comparison that were in the same geological and pressure regions, had a minimum of 2 years of production information, and were stimulated with various fracture-fluid systems.
In one of the analyzed areas, a definite trend was identified; it was found that wells drilled in a certain orientation performed better than wells drilled with other orientations.
Completions and hydraulic-fracturing costs were gathered from public sources in order to understand the cost differences between areas and types of fracture-fluid systems. Using decline curves and cost information, full-cycle economics were run on the "average" well for each area in order to determine the net present value (NPV) of each area.
This case study shows there is value in optimizing fracture designs through look-back studies, and there is a need to focus on more-effective fracture-treatment designs in unconventional oil development. The overall results of the study showed: (1) the choice of fracture-fluid system is a key component in optimizing economics in the Cardium halo areas; and (2) the optimum fluid system varies in different areas of the Cardium.