Permeability reduction provided by conventional polymer gels is affected by harsh reservoir conditions. Harsh conditions are defined by high temperature (> 75°C), high salinity, high divalent ions and the presence of H2S. Polymer gels undergo syneresis when exposed to high salinity and hardness reservoir brines. We evaluated conventional polyacrylamide-based polymer (HPAM)-gels and other modified HPAM-gels with molecular weights between 2-20MM Daltons for gelation time and long-term gel stability under harsh conditions. In addition to polymer degradation, the cross-linkers are also sensitive to harsh reservoir conditions. Specifically, H2S can consume cross-linkers and inhibit gelation. The cross-linkers tested were Chromium (III) Acetate and Chevron Unogel formulation consisting of a combination of hexamethylenetetramine (HMTA) and hydroquinone (HQ). High performing gels were tested for sensitivity to high salinity brines and H2S in a limited number of experiments. The gels were observed for gel strength, and syneresis with time. The goal of our work was to identify a combination of polymer and cross-linker that would provide effective conformance under harsh conditions. Sulfonated polyacrylamide (ATBS) polymers were found to provide better resistance to high salinity/hardness brines than partially hydrolyzed polyacrylamides in high temperature conditions. The addition of hydrophobic groups to the sulfonated-acrylamide backbone does not increase the hardness tolerance of the polymer. Higher concentration, low molecular weight sulfonated polymers are recommended for use at high temperature and salinity. Polymer gels made with 2MM Dalton polymer show less syneresis with time compared to higher molecular weight polymer at the same polymer concentration. HMTA/HQ ATBS polymer gels are preferable to chromium (III) ATBS polymer gel for high temperature and salinity conditions. Chromium (III) ATBS polymer gels show more susceptibility to syneresis compared to organic crosslinked gels at same polymer concentration. HMTA/HQ crosslinker is ineffective in the presence of hydrogen sulfide. Gelants consisting of HMTA/HQ do not mature into rigid gels after 14 days of exposure to sour gas. Preformed HMTA/HQ gels lose strength upon exposure to sour crude. This is mostly due to HMTA ability as a sour gas/crude sweetener. Chromium (III) gels form weak gels in the presence of sour gas. Chromium competes with sulfide ions to produce insoluble chromium sulfide leading to consumption of crosslinker and poor gelation. Malonate and tartrate are effective gel retardants for chromium (III) polymer gels. Malonate is better at extending onset of gelation for longer periods of time. Tartrate is more effective for shorter gelation time at lower concentrations.

Summary Temperature traces from multiple rates are used to estimate the production-inflow profile and layer permeability and skin by use of a transient coupled reservoir/wellbore model. Production-logging-tool (PLT) temperature traces from two rates show heating of approximately 6–11°F above the geothermal because of the Joule-Thomson expansion of the reservoir oil. Production is single-phase oil from a high-pressure oil reservoir. Nonlinear regression was used to automatically adjust the layer permeability and skin values until the observation temperature traces from both rates were matched. History matching the temperature data provides a quantitative estimate of the skin and permeability within each contributing layer; this cannot be obtained from conventional pressure-transient analysis, which, unless for highly specialized cases, provides only a single value of permeability and skin. The production-inflow profile is then constructed by use of the history-matched layer permeability and skin values. In addition to the wellbore-temperature profiles, temperature and pressure profiles within the reservoir will be shown that illustrate the relative effect of the reservoir permeability and skin on the wellbore-temperature responses. The approach in this paper is different from many of the previous studies in the literature, in which only a single temperature trace is history matched and often under the assumption of steady-state conditions. Furthermore, no studies were found in which multiple temperature traces were matched by use of a transient model in which the temperature data were field data as opposed to synthetic data. Information on the coupled reservoir/wellbore model and the optimizer will be provided.

Layer flow contributions are increasingly being quantified through the analysis of measured sandface flowing temperatures. It is commonly known that the maximum temperature change is affected by the magnitude of the drawdown and the Joule-Thomson expansion coefficient of the fluid. Another parameter which strongly impacts layer sandface flowing temperatures is the layer permeability. Aside from determining the drawdown, the layer permeability also affects the ratio of heat transfer by convection to conduction within a reservoir. The impact of permeability can be represented by the Peclet number, which is a dimensionless quantity representing the ratio of heat transfer by convection to conduction. The Peclet number is directly proportional to reservoir permeability. Through dimensionless analysis it will be shown that for a given drawdown (based on a dimensionless Joule-Thomson expansion coefficient, JTD) the temperature change diminishes at low Peclet numbers and increases at high Peclet numbers. This implies that for low permeability reservoirs such as shale gas or tight oil, the temperature changes will be minimal (less than 0.1 °F) despite the large drawdowns in many instances. Dimensionless analysis is performed for both steady-state and transient thermal models. Results from multi-layer, transient simulations illustrate the ability to identify contrasting permeability layers based upon the Peclet number effect.

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The influence of hydraulic fractures during production is to alter the wellbore/sandface temperature changes by reducing the magnitude of the Joule-Thomson expansion effect. Compared to an unfraced completion in which the flow path of the reservoir fluids is purely radial, the presence of hydraulic fractures lengthens the flow path the reservoir fluids must take by creating a linear flow geometry. For a given drawdown, therefore, the local pressure gradients are lower in a hydraulically fractured completion compared to a non-hydraulically fractured completion. Through dimensionless analysis it will be shown that the Joule-Thomson effect is proportional to the local pressure gradient squared which implies a reduction in the Joule-Thomson effect for a hydraulically fractured completion compared to a non-hydraulically fractured completion. Simulations from a thermal reservoir/wellbore model will be presented comparing the thermal responses between hydraulically fractured and non-hydraulically fractured completions. It will be shown that the presence of hydraulic fractures can reduce the wellbore/sandface temperature changes by much as 85% compared to a non-hydraulically fractured completion. Additionally it will be shown that measurement of sandface and wellbore temperatures during production can provide information to determine which intervals have been successfully hydraulically fractured, and to a lesser extent a qualitative assessment of hydraulic fracture efficiency.