|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Saberhosseini, Seyed Erfan (Islamic Azad University) | Mohammadrezaei, Hossein (Iranian Offshore Oil Company) | Saeidi, Omid (Iranian Offshore Oil Company) | Shafie Zadeh, Nadia (Natural Resources Canada) | Senobar, Ali (Iranian Offshore Oil Company)
Pre-analysis of the geometry of a hydraulically induced fracture, including fracture width, length, and height, plays a crucial role in a successful hydraulic-fracturing (HF) operation. Besides the geometry of the fracture, the injection rate should be optimal for obtaining desired results such as maintaining sufficient aperture for proppant placement, avoiding screenouts or proppant bridging, and also preventing caprock-integrity failure as a result of an extensively uncontrolled fracture in reservoirs. A sophisticated numerical model derived from the cohesive-elements method has been developed and validated using field data to obtain an insight on the optimal fracture geometry and injection rate that can lead to a safe and efficient operation. The HF operation has been conducted in an oil field in the Persian Gulf with the aim of enhanced oil recovery (EOR) from a limestone reservoir with low matrix permeability in a horizontal wellbore. The concept of the cohesive-elements method with pore pressure as an additional degree of freedom has been applied to a 3D fully coupled HF model to estimate fracture geometry, specifically fracture height as a function of the optimal injection rate in a reservoir porous medium. It was observed that by increasing injection rate, all the fracture-geometry parameters steeply increased, but the fracture height must be controlled to be in the reservoir domain and not surpass the caprock and sublayer. For the reservoir under study with the maximum height of 100 m, length of 250 m, width of 100 m, permeability of 2 md, and porosity of 10%, the optimal fracture height is 73.4 m; the average fracture width and half-length are 12.8mm and 55.4 m, respectively. Therefore, the optimal injection rate derived from the fracture height and geometry is in this case 4.5 bbl/min. The computed fracture pressure (49.55 MPa = 7,283.85 psi) has been compared with the field fracture pressure (51.02 MPa = 7,500 psi), and the error obtained for these two values is 2.88%, which showed a very good agreement.
Afsari, Meisam (Iranian Offshore Oil Company) | Amani, Mahmood (Texas A&M U at Qatar) | Razmgir, Seyed Ahmad Mohsen (Iranian Offshore Oil Company) | Karimi, Hassan (Schlumberger) | Yousefi, Saman (National Iranian Drilling Company NIDC)
Drilling through subjected mature offshore oil field is made more challenging by problems arising from wellbore instability, mud losses, excessive cutting, tight hole, stuck pipes and kick/flow zones for last few years. These problematic layers have caused quite a significant NPT (non productive time) during drilling.
For better understanding of factors causing wellbore instability problem and to predict mud weight window to be used for future wells, construction of mechanical earth model (MEM) was essential.
Mechanical Earth Model (MEM) is a numerical representation of the state of stress and rock mechanical properties for a specific stratigraphic section in a field or basin2.
In this study main drilling problems for each drilling interval in this field were described afterward different stages for construction an 1D Mechanical Earth Model (MEM) for the field was established. It was then demonstrated that how 1D MEM could be used to predict and prevent the common instability problems encountered during drilling.
For making MEM different sources of data including, drilling data, formation evaluation data, well testing, etc were used.
After making MEM for the field, safe and intact mud weight window was determined and according to that, suggestions for optimum mud weight for stable borehole on each interval was made.
MEM for this field can now be used to predict not only the safe mud weight window and possible drilling hazards, but can also be used for studies like reservoir compaction, sand production, and perforation stability and so on.
The subject field is located in central part of the Persian Gulf and its structure is result of salt tectonic. On this domal structure, several faults trends of NW-SE are visible on the seismic data which have produced some grabens. Most sections of the stratigraphic column are dominated by carbonates with thin lamination of shales and evaporate except one sandstone layer. 3D geological view of the field is shown in Figure1.
This field has been experiencing some drilling problems for last few years. Mud losses, excessive cutting, tight spot, stuck pipes, and kick/flow zones are some of the commonly occurred problems. Some stratigraphic levels have been quite difficult to drill through, which has caused quite a significant NPT (non-productive time). In some cases, side-track holes had to be drilled from the original hole. Generally, it is not so easy to predict what kind of problem the well would get into.
Minimizing the risk of problems related to geomechanical properties requires understanding the geomechanics of well construction and field, In order to be able to address the drilling problems and propose the solutions for the future wells which could optimize drilling and production performance of the subject field.
Here the methodology of building a MEM is presented. Generally geomechanical model relates dynamic elastic properties to static equivalents. These elastic static properties are then used to characterize formation strength and in-situ stress4. The MEM consists of depth profiles of elastic or elasto-plastic parameters, rock failure mechanisms, geologic structure, stratigraphy, well geometry, earth stresses, pore pressure and stress direction. After construction, this model can be used to identify geomechanical problems and to consider those problems for planning future wells.
This paper examines and compares Natural and Artificial Gas Lift performance of one of the Iranian Offshore fields. Before the results of this study, gas channeling from the upper gas layer, a phenomenon which causes gas streams to pierce into some of the wellbores, was characterized as a negative effect which should be treated or repaired. On the other hand, regarding that this is a fractured under-saturated reservoir with an active aquifer mechanism, it was foreseen that applying immiscible gas and water injection in this reservoir in order to increase recovery factor are ineffective; and studies supported this idea. With respect to the growing amount of water production, need to further study Artificial Lift Methods was assumed essential. Considering operational conditions and abundance of excessive gas in this field, a gas lift system was designed and the optimum injection points with best recoveries were identified. However, reservoir simulation surprisingly demonstrated that when gas channeling from the upper gas layer is taken into account, oil production rates exhibit a significant increase. This could be interpreted as Natural Gas Lift.
In this paper, we indicate how accidental gas channeling in the wells of this reservoir has prompted oil production rate to raise. Results of well modeling by PROSPER software, considering different flow scenarios, were imported into reservoir simulator and final recoveries were observed during a certain time period. Conclusively, it is suggested that controlling gas channeling in these wells by employing Natural Gas Lift Technology would maintain oil production capacity. According to the results, total field oil recovery factor would be almost 4 percent more than natural depletion during 21 years and that would be the most economical, applicable and effective way to improve recovery factor in this reservoir.
Building the Reservoir Dynamic Model
Dynamic Model of the studied reservoir was upscaled by using static model so by adding fluid properties, SCAL data, pressure and water oil contact and its production history have been provided by ECLIPSE Office Software and performed by Eclipse 100. (Fig-1)
Even though the analysis of Pressure Information for wells indicated the existence of fractures, the initial dynamic model is a single porosity model which model history matching was not acceptable. (Fig-1)
Inflow performance relationship (IPR) curves have been extensively studied in the petroleum engineering community; from the classic Vogel’s method for vertical wells to modified models for horizontal wells. Previous works have indicated that the performance of horizontal wells can be different from that in vertical wells due to their more complex geometries. Hence, this encourages us to aim for modified IPR correlations.
Modeling the production performance in a horizontal well requires an understanding of the parameters that may affect the fluid flow geometry and well/reservoir interface. In this work, numerical modeling was employed to study the performance of horizontal wells under different well/reservoir conditions. A new IPR relationship was proposed for horizontal wells producing from solution-gas drive reservoirs along with a modified absolute open-flow potential (AOFP) which was proposed initially by Kabir. This was to introduce new terms that accounted for the effect of bubble-point pressure and recovery factor which were found to be significant. The developed model was tested against field data, and it was also evaluated and compared with the current IPR curves.
In order to generate an IPR curve for a horizontal well at the specified recovery factor, simulation models were constructed and run for each bottomhole pressure. Then, computer codes were used to extract the results from each results file. Next, the coefficicents and parameters of the equations were obtained from non-linear regression and curve fitting. Then, IPR curves from the analytical model were generated at specified well/reservoir conditions, and at a certain recovery factors. Finally, the results from the model were compared to the simulation model and field data.
This work confirmed that the IPR curves in horizontal wells producing from a saturated reservoir may need modified relationships due to more cmplex flow geometry and well/reservoir interactions. The developed three-parameter IPR relationship presented reasonable accuracy as was compared to the current models and field/simulation data. Also, the new AOFP equation showed a reasonable error of 3% compared to the simulation results.
Improving the rate of penetration (ROP) is one of the key methods to reduce drilling costs. Several ROP models have been developed and modified based on the concept where unconfined compressive strength (UCS) is inversionally proportional with the rate of penetration. These models can predict the rate of penetration of different bit types in an oil or gas field with a reasonable degree of accuracy. The ROP model studied herein relates the rate of penetration to operating conditions and bit parameters in addition to the rock strength. Also, the effects of bit hydraulics and bit wear on rate of penetration are included in the model.
In this paper, the drilling performance was optimized, using the ROP models, for upcoming wells in one of the Persian Gulf carbonate fields. Based on previous drilled
wells a rock strength log along the wellbore is created and modified to mach the the new well survey. The rock strength is back calculated from the ROP model which
includes bit design and reported field wear in conjunction with meter by meter operating parameters, formation lithologies and pore pressure. By conducting a number of
simulations a learning curve was constructed to obtain the optimum bit hydraulics, best combination of operational parameters and the most effective bit design.
Based on the proposed ROP model, a simple and useful simulator was developed. This methodology can be used in pre-planning and post analysis to reduce drilling cost where previously drilled wells exist.
Reshadat oilfield is located in the central Part of the Persian Gulf. This field is an anticline with an approximately North- South trend. The Upper Sarvak Formation is a potential reservoir in this area. Mishrif resvoir in this field has been divided into five zones. Zone A, (the uppermost) is recognized the best reservoir zone. Diagenetic processes including (desolation, dolomitization and fracturing) improved reservoir qualities. As a result of diagenetic process (dissolution), stratighraphic trap (diagenetic) has been created, and zones A and B are shaped into pinch out trap. Weathering dramatically improves the reservoir permeability and thus controls the extent of this diagenetic trap. Investigation shows that local unconformity in the southern flank of Reshadat oilfield, created the highest reservoir zones in this part. Consequently; reservoir quality of zones C and D have been improved.
The inversion of the seismic data to acoustic impedance has allowed for better definition of the main lithological units. Depth conversion has been performed and accurately ties the interpreted horizons to the available well data.The inverted impedance clearly highlights facies and porosity variations within Mishrif interval which not apparent on seismic data. The combination of seismic interpretation and seismic inversion has improved our understanding and definition of the Mishrif reservoir.
Applying reasonable cutoffs for porosity and permeability, reveals valuable zones (A&B) in this portion of field. These zones are located in the west and northwest of Reshadat oil field. The study shows that thickness of the valuable zones are increasing towards the west and the northwest and decreasing in the center and south of this field.
The study has taken the form of an initial interpretation data followed by an inversion to acoustic impedance and subsequent fine-tuning of interpretation on the impedance data. The advantage of this offers is a reduction of wavelet and tuning effects and the generation of 3D geological model matching the original seismic data. In addition reservoir properties such as porosity can be estimated from products of the inversion process.
The main results of the study are time and depth maps of horizons (Figs.1, 2): near top Damam, top Mishrif, top Khatiyah, top Kazhdoumi and etc.
In addition 3D acoustic impedance are generated in time depth.
(Figure in full paper)
Mishrif - Khatiyah Formations:Mishrif reservoir contains several lithologies. Each of which exhibits differing sedimentological, and petrophysical properties and each representing a distinct subenvironment. Interfacies boundaries are not clear because adjacent facies grade laterally and vertically into each other. The formation consists of the following facies:
Lagoonal/ back reef, rudist biostrom, algal boundstone, shallower sub basinal (or outer reef margin), and deeper sub-basinal (slope margin) .The contact between Mishrif shallow marine reef facies and khatiyah deeper marine facies in a gradual transition (Fig.4). There is thinning of the Mishrif on the crest of structures. This is largely related to the erosion during early upper Cretaceous uplift. It is believed that most of the present structures originated during upper Cretaceous uplift. The Khatiyah formation consists of interbedded limestone and shale with a total thickness averaging 120m in the Reshadat.