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.
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Nagar, Ankesh (Cairn Oil & Gas, Vedanta Ltd) | Manish, Kumar (Cairn Oil & Gas, Vedanta Ltd) | Srivastav, Pranay (Cairn Oil & Gas, Vedanta Ltd) | Nekkanti, Satish (Cairn Oil & Gas, Vedanta Ltd) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd) | Srivastav, Preyas (Cairn Oil & Gas, Vedanta Ltd)
This paper describes simulation solution for CT(Coil Tubing) based WBCO in flowing ESP/Jet Pump wells for scale/polymer debris deposition removal prior to any treatment in well, such as – Formation stimulation, ESP treatment, etc. It also describes prediction for requirement of Surface Well Test spread support to assist Nitrogen assisted WBCO. The paper describes new way of simulation for CT WBCO job in artificially flowing wells to predict decreased Liquid rate from reservoir, CT pressure & friction pressure losses. The modelling is done in Prosper and Cerberus, the results of which are validated with surface well test and Multiphase flow meter data recorded during the jobs. The results observed were very close to modelled with a number of advantages such as – No loss returns, higher lifting velocities, prediction of increased/decreased reservoir liquid rate affecting Motor winding temperature in ESPs, no settling of debris, post job Increased Liquid gain from well, decreased tubing friction pressure loss
Alternating high and low concentration polymer flooding has been proposed and applied in some offshore oilfields to improve polymer flooding efficiency, but the research of pressure analysis in alternating polymer flooding reservoir is rare, this work presents a numerical pressure analysis method of three-zone composite model for formation evaluation. The type curves have seven regimes in three-zone composite model. The characteristic is the obvious upturn of pressure derivative curve in transient regime between high concentration and low concentration polymer solution. Formation parameters can be interpreted by history matching and formation evaluation can be conducted based on this model. As an important part of formation evaluation, formation damage as a result of adsorption of polymers in porous media is evaluated by comparing the interpreted permeability with the original value before polymer flooding. The field test data proves that this proposed method can accurately evaluate reservoir characteristics in alternating polymer flooding reservoirs, which emphasizes the potential application of this method in petroleum industry.