Summary The Bakken is one of the most prolific plays in North America, but even with the deployment of horizontal wells and hydraulic fracturing, anticipated recovery factors under primary depletion are usually in the range of 10% to 20%. Waterflooding has been a nearly ubiquitously deployed technology in conventional reservoirs to enhance recovery beyond primary depletion. However, the Bakken's ultra-tight, largely oil-wet nature limits the potential of waterflooding. Moreover, the challenges associated with sweep after the formation has been hydraulically stimulated must also be overcome. To address these challenges an optimally-spaced well to well surfactant flooding technology is proposed. Optimal well spacing, from a flooding perspective, can mitigate rapid breakthrough while minimizing the distance through the matrix that the injection fluid must travel. An optimally designed chemical system can enhance imbibition rates and favorably alter wettability to enable economic recovery. Moreover, environmental and community benefits can be realized by utilizing abundant produced water to operate a surfactant flooding process in the Bakken. This paper discusses a comprehensive experimental program exploring the potential of surfactant flooding in the Bakken along with a field communication study and corresponding scaled-up, well-to-well flooding models for an optimized surfactant flooding process. Results from the experimental program are provided which showcase the potential of advanced chemical systems. A brief overview of a core-scale natural fracture study and field-scale well-to-well communication study is provided. Lastly, up-scaled models, showing the potential societal and economic benefits that can be attained from an optimally designed surfactant flood, are presented.

In SAGD (Steam Assisted Gravity Drainage) operations the produced fluids are complex water-in-oilin-water (W/O/W) emulsions. A diluent is often added to reduce the density and viscosity of the heavy crude oil. However, the quality and composition of the diluents may in some cases increase emulsion stability and cause the dehydration of the oil to be more difficult as there are more surface-active agents added to the oil coming from the diluent streams. To simulate temperature and pressure conditions during SAGD operations, this work studied the effect of three diluents on interfacial rheology of a Canadian heavy oil and synthetic brine at 120°C and 130 psi and then correlated with emulsion stability and oil dehydration. When compared to 25°C, all three diluents exhibited higher higher compressibility at 120°C, while the initial interfacial tension, "phase change" area ratio (area ratio at which the phase change from high compressibility region to low compressibility region), and crumpling ratio (ratio of the compressed surface area to the original area at which the interface starts to collapse) exhibited a more complex behavior. The higher interfacial tension and higher compressibility were correlated with the lower emulsion stability at increasing pressure and temperature in the absence of treating chemicals. Increasing ageing of the film from 10 minutes to 1 hour at 120°C had a similar effect on the three diluents, suggesting the formation of a more elastic film as asphaltenes start to cross-link on the interface. The effect of demulsifiers (emulsion breakers-EB and reverse emulsion breakers-REB) on interfacial was also investigated at RT and 90°C. Demulsifiers that produced the minimum interfacial tension (IFT) with changing concentrations demonstrated to be the best demulsifiers in the bottle tests. A synergistic effect in reducing IFT was found when EB and REB when combined.

The field in question consists of four reservoirs with varying barium levels (15 ppm to 320 ppm). For pressure support seawater injection has been applied from the start of field life. Prior to field start up, studies were conducted to review the order of expected injection water breakthrough for each well, the location of breakthrough along the length of the production sections, the feasibility of bullhead deployed squeezes and the implications of barium ion stripping. These issues were all assessed to generate a scale management strategy for the field.Despite uncertainties in the original reservoir model, the order of injection water breakthrough across the field was observed to be correct and the information on placement proved very useful in building scale squeeze treatments.The challenge of rapid injection water breakthrough in the field during its early life was addressed with development of pre-production squeeze treatments applied during new well completions. This eliminated the need to shut in wells whilst awaiting mobilisation of DSVs for treatment deployment. As the field matures, tailored scale squeeze treatments were developed for each of the 25 production wells. Over the life of the wells the squeeze designs were updated to take into account changing water rates, changing water composition and thus MIC for the squeeze chemical. The positive contribution of the downhole continual injection chemical was also shown to extend the squeeze lifetimes by allowing a lower MIC value to be used for treatment design in the production section of the wells.Optimisation of the scale management programme has seen wells considered to be outside the scale window eliminated from the squeeze treatment campaigns, reduction in chemical volumes being applied and extended squeeze lifetime for treatments based on monthly review of well performance/water chemistry/inhibitor residuals.

The practice of scale squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. Many of these studies have focused on sandstone reservoir with less extensive studies carried out on carbonate substrates. This paper details work carried out using ‘squeeze life enhancer’ chemicals within the Preflush and Overflush stages utilising a co-polymer containing a quaternary amine group to evaluate this chemicals effect on phosphonate scale inhibitor retention process. Phosphonate scale inhibitors are known to provide excellent squeeze lifetimes in carbonate reservoirs due to their strong interaction with the negatively charged formation using hydrogen ion bonding at low pH or calcium ion bridging at higher pH however with the aid of an enhancer chemical it was hoped to help the retention/release process and so provide further improved squeeze lifetimes. The location of the enhancer chemical within the squeeze process was the focus of the study. Enhancing adsorption of the scale inhibitor is not objective of this application study rather ensuring that the retained chemical is released into the flowing brine during production which is a challenge in carbonate reservoirs. Laboratory work will be presented which evaluates the effect of using a polyaspartate enhancer within either the preflush or overflush stages to extend the lifetime of a commonly applied phosphonate scale inhibitor. These tests have been carried out using pack floods at 85°C with synthetic Middle East produced water and the details of the extension in treatment life observed are correlated to the inhibitor type tested and the sequence of application of the polymer enhancer utilised. The study shows how the different functional groups within the scale inhibitor interact with the carbonate mineral surface and polymer enhancer to extend treatment lifetimes and so potentially reducing the frequency of squeeze treatments and therefore total cost of operations and it is order of application of these chemicals to the rock surface that prove to be critical to the extension observed.

One of the common causes of gas wells productivity loss is attributed to liquid accumulation near the wellbore over the production life of the wells. For gas condensate reservoirs, when the bottomhole pressure falls below the dew point pressure, liquid hydrocarbon drops out of the gas phase, residing in the near wellbore region and causing condensate block. Fracturing fluid also contributes to liquid blockage as only 5 to 30% of fracturing fluids are recovered from the reservoir. For a tight shale formation where the pore sizes are as small as nanometers, capillary pressure is large enough to cause liquid entrapment in the pore body reducing the relative permeability to the gas phase. A variety of methods such as gas cycling, super critical CO2 injection, solvent injection, and wettability alteration using fluorinated surfactants/polymers have been suggested to treat liquid block or banking (i.e., water and condensate). However, these methods are either not effective or expensive, and do not provide a good return on investment. As capillary pressure depends on surface/interfacial tension (ST/IFT) and the contact angle, a treatment method that combines the effect of ST/IFT reduction and wettability alteration can be applied to lower capillary pressure, thus, to enhance liquid unloading. In addition, reducing the ST between gas and the liquid phase (water/gas condensate) will increase the carrying capacity of the gas phase with respect to the banked liquid phase. This paper presents a practical laboratory testing procedure developed to screen and recommend cost effective production enhancement formulations to treat liquid blocking. Based on laboratory test results obtained from this testing procedure, a non-fluorinated production enhancement formulation was recommended for a field trial. The recommended formulation was tested at two gas wells: one vertical and one horizontal in North Texas. The proposed formulation was used in the fracturing fluids when the wells were re-fractured. Production data from the two wells have shown a sustained increase in gas production and water recovery rate. The lessons learned here can be used as a guideline to increase production life of existing gas wells and to maximize hydrocarbon (gas and associated condensate) recovery rates.