Well drainage areas and shapes for wells in reservoirs with aquifer contact or gas-oil contact (constant pressure boundary) take varying shapes, such as, water coming from one-side (edge water drive) to water coming from 3-sides when the 4th-side is a sealing fault. This information is important in well test interpretations, peripheral flooding, aquifer injection, gas and CO2 aquifer storage, geothermal reservoirs, and any subsurface recovery schemes involving injection-production well pairs. A knowledge of well drainage shapes is helpful in optimizing well placement, well productivity estimations, and to maximize reserves. Results show that for a 2-well 3-sided water-drive reservoir system, each well drains an equal area when the well-rates are equal; however, the drainage areas of a well increases logarithmically with an increasing ratio of its flow rate to that of an adjacent well. In case of a multiple well system, results show that the drainage area of well closer to water contact is smaller than that of an interior well, farther away from the water-contact. Results are presented in graphical form and equations to determine the drainage area and shapes for varying production rate-ratios between wells in a multiple constant pressure boundary rectangular reservoir. An algebraic procedure is presented to generalize results from a 2-well system for extension to a multi-well system with similar multiple constant pressure boundary conditions. The equations yield result within 5% of those obtained from complex streamline simulations. A well's location within its drainage area is needed to determine mean well pressures from MBH (Matthews-Brons-Hazebroek) functions for water drive reservoirs, and to estimate productivity index and cumulative water influx volumes.
Raghunathan, Murali (ADNOC - Al Dhafra Petroleum Company) | Alkhatib, Mohamad (ADNOC - Al Dhafra Petroleum Company) | Al Ali, Abdulla Ali (ADNOC - Al Dhafra Petroleum Company) | Mukhtar, Muhammad (ADNOC - Al Dhafra Petroleum Company) | Doucette, Neil (ADNOC - Al Dhafra Petroleum Company)
A novel workflow was developed to select an optimal field development plan (FDP) which accounts for a number of associated uncertainties for an oil Greenfield concession that has a limited number of wells, production data and information. The FDP was revisited and updated to address the additional data acquired during the field delineation phase. The study in Ref-1 demonstrates the comprehensive uncertainty analysis performed and the resulting optimized FDP. The FDP was developed to minimize the economic risk and uncertainty. Further field delineation activities have revealed a north and south extensions with an increase in hydrocarbon accumulation by 115%. A reservoir dynamic model was updated because of the increase in HC and input data from 17 wells. A workflow has been created with a suitable development option to consider the recently appraised areas, which are: - Updated saturation height functions (SHFs) which improve the match between newly drilled wells and water saturations logs - Updated reservoir models which were based on well tests and new analytical interpretations - History matching well test data with new acquisition data - Optimized field development options, that cover additional areas - Inputs to reservoir surveillance plan Be implementing following an extensive analysis the most robust development concept was selected and will now in the field.
Well RXY is located in Cairn’s Ravva offshore field in the Krishna-Godavari Basin in India. One goal for the field was significant crude production by means of a secondary reservoir section. This paper summarizes key engineering discoveries and technical findings observed during the execution of 200 hydraulic-fracturing diagnostic injection tests in the Raageshwari Deep Gas (RDG) Field in the southern Barmer Basin of India. Reliance Industries and BP are going forward with the expansion of a huge field off the east coast of India that is expected to fill 10% of the country’s energy needs. India Asks Big Oil Companies "Where Do You Want to Drill?" India will test whether it can reach its ambitious goal of reducing oil and gas imports by 10% by 2022 with an upcoming auction of oil properties.
Thin oil columns overlain by free gas and underlain by water pose difficult problems in well spacing and completion method, production policy, and reserves estimation. In this context, "thin" is a relative term. Whether an oil column is considered thin depends on costs to drill and produce the accumulation. For example, in the Bream field (Australia Bass Strait, 230 ft water depth), 44 ft was considered thin, whereas in the Troll field (offshore Norway, 980 ft water depth), 79 ft was considered thin. Onshore U.S.A., 20 ft is considered thin. Irrgang takes a pragmatic approach, defining thin oil columns as those that "will cone both water and gas when produced at commercial rates."
Selection of appropriate completion equipment requires consideration of not just production operations, but other activities such as injection or treatment. Shutting-in the well also creates changes in temperature and pressure that need to be considered. This article discusses the temperature-depth profiles that occur under different modes of operation. While the primary application may be oil or gas production, any subsequent operations (such as acidizing or fracturing the well) and their associated pressure and temperature changes are extremely important to packer utilization success. Typical temperature vs. depth profiles are illustrated in Figs 1 through 4.
In most US unconventional resources development, operators usually first drill the parent wells to hold their leases, and then infill wells are drilled. A challenge raised from this process is the well-to-well interference or frac-hits. Fractures in infill wells have a tendency to propagate toward the depleted region induced by the pressure sink of the parent well, resulting in asymmetric fracture growth in infill wells and frac-hit with the parent well. One of the available mitigation methods is to inject water into the parent well to re-pressurize the depleted region. Though several papers have released positive results from their numerical studies, both negative and positive responses are reported from filed applications. This paper focused on identifying the mechanism and key factors controlling the effectiveness of the subsequent parent well water injection. A coupling reservoir geomechanical model was built to evaluate the pressure and stress change caused by the parent well production and subsequent parent well water injection. The reservoir and geomechanical models are prepared based on a dataset from Eagle Ford Shale. At desired time steps, pressure distribution from reservoir simulation is used to calculate the corresponding stress status.
In this numerical simulation study, both reservoir properties and operating conditions are considered. Considering the production loss during the parent well injection, the maximum injection time is set to be 1 month. The magnitude and orientation of horizontal principal stresses within and around the depleted region are used as a criterion to evaluate the effectiveness of subsequent parent well injection. A general observation is that between two adjacent fracture clusters, 3 regions could be identified whose behaviors are significantly different during production and injection. The subsequent water injection could only restore the pressure and stress in region 1, which is within 10 ft to the fractures. Region 2 is severely depleted but the injection of 1 month generates no improvement in this region due to the low matrix permeability. Region 3 might exist, where oil is not produced, but Shmin reduces and this reduction could not be restored through injection of 1 month. If the injection generates a relatively uniform pressure distribution, then SHmax angle change could be reduced to 0. We also observed that: (1) for our case, an injection pressure equal to the initial reservoir pressure is recommended. Using low injection pressure, Shmin is found out to be lowest in fractures, which may make infill well fractures tend to propagate into and hit the parent well fractures. However, if injection pressure is increased to larger than the initial reservoir pressure and smaller than the minimum horizontal stress, the improvement is insignificant; (2) Comparison between uniform and non-uniform hydraulic fracture geometries shows that hydraulic fracture geometry mainly affects the depletion region far away from the wellbore. i.e. along the long fracture tips. After injection, in the case with long uniform fractures, the Shmin value in long fracture tips is still lowest. (3) An SRV with high permeability significantly extends the depletion region. If the permeability is not large enough i.e. 0.01 mD, after injection of 1 month, the restored Shmin is about 1000 psi lower than the base case without SRV. (4) Using low bottomhole pressure in production, restored pressure and stress are about 500 psi lower than the base case; and due to the large pressure contrast between region 1 and region 2, the SHmax angle change could not be reduced. (5) In a reservoir with normal pressure, as the pressure change is not large, it is easier for the subsequent injection to take effect.
This paper provides significant insights into how to design a successful subsequent water injection process in a parent well, mitigate the negative effects of frac-hits, and maximize production of both parent and infill wells.
Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.
Aslanyan, Artur (Nafta College) | Grishko, Fedor (Salym Petroleum Development N.V.) | Krichevsky, Vladimir (Sofoil) | Gulyaev, Danila (Sofoil) | Panarina, Ekaterina (Sofoil) | Buyanov, Anton (Polykod)
A waterflood study has been performed on a heterogeneous oil deposit with a rising water-cut and production decline after 10 years of commercial production.