Multilateral completion systems allow the drilling and completion of multiple lateral boreholes within a single mainbore. This allows for alternative well-construction strategies for vertical, inclined, horizontal, and extended-reach wells. Multilaterals can be constructed in both new and existing oil and gas wells. General benefit provided by multilateral well design is barrel cost reduction. Multilaterals help to both reduce CAPEX and OPEX of the project and increase production.
The oil and gas industry is becoming more technologically advanced every day. As automation, artificial intelligence (AI) and robotics improve, it may be increasingly tempting to employ automatic means to accomplish industry goals. The most comprehensive list was developed by Thomas B. Sheridan and W. L. Verplank. Levels of automation range from complete human control to complete computer control. Parasuraman, Sheridan, and Wickens went on to introduce the idea of associating levels of automation to functions.
Figure 1 shows the type of production response that is possible when applying a polymer gel treatment to a waterflood injection well to improve sweep efficiency. The figure shows the combined production-response of the four direct offsetting production wells to the gel-treated injection well. The gel treatment was applied for waterflood sweep-improvement purposes to the naturally fractured Embar carbonate formation surrounding Well O-7 of the highly mature SOB field in the Big Horn basin of Wyoming. The wide variations in water/oil ratio (WOR) and oil production rate are quite common in many of the well patterns of this highly fractured reservoir. Sydansk provides more details regarding the 20,000 bbl gel treatment.
A directional well can be divided into three main sections--the surface hole, overburden section, and reservoir penetration. Different factors are involved at each stage within the overall constraints of optimum reservoir penetration. Most directional wells are drilled from multiwell installations, platforms, or drillsites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved.
In July 2012, SPE held a two-day summit on human factors to create a common understanding of the strategic challenges for the oil and gas E&P industry, to identify what is known and unknown in the field, and to explore possible actions to accomplish the needed change indicated by the U.S. National Commission on the Deepwater Horizon Oil Spill and Offshore Drilling report. Attendees created a technical report based on the discussions and conclusions at the summit as a guideline on the human factors risks in E&P operations and what can be done to reduce those risks and increase safety. Members of the summit decided that the industry must move to an organizational culture in which process safety is as well managed as personal safety. Leadership is critical to a process safety culture. The decisions, actions, and statements made by leaders, the reward and incentive structures that leaders implement, the way leaders behave and interact with people throughout the organization, and the decisions and actions they take to balance safety against commercial imperatives, directly determine the attitude to safety within an organization.
Typically, it is banded or clamped to the production tubing from below the wellhead to the ESP unit because it is not designed to support its own weight. It is a specially constructed three-phase power cable designed specifically for downhole well environments. The cable design must be small in diameter, protected from mechanical abuse, and impervious to physical and electrical deterioration because of aggressive well environments. They are available in a wide range of conductor sizes or gauges. They can be manufactured in either round or flat configurations, using several different insulation and metal armor materials for different hostile well environments.
Water management can significantly add to the cost and environmental footprint of oil production and innovations in water management can provide significant economic and environmental gains. New treatment technologies make recycling of water for hydraulic fracturing possible. Methods for recycling fracking water include anaerobic and aerobic biologic treatment; clarification; filtration; electrocoagulation; blending (directly diluting wastewater with freshwater); and evaporation. Generally, anaerobic treatments on wastewater are implemented on concentrated wastewater. Anaerobic sludge contains a variety of microorganisms that cooperate to convert organic material to biogas via hydrolysis and acidification.
Recent studies have indicated that Huff-n-Puff (HNP) gas injection has the potential to recover an additional 30-70% oil from multi-fractured horizontal wells in shale reservoirs. Nonetheless, this technique is very sensitive to production constraints and is impacted by uncertainty related to measurement quality (particularly frequency and resolution), and lack of constraining data. In this paper, a Bayesian workflow is provided to optimize the HNP process under uncertainty using a Duvernay shale well as an example.
Compositional simulations are conducted which incorporate a tuned PVT model and a set of measured cyclic injection/compaction pressure-sensitive permeability data. Markov chain Monte Carlo (McMC) is used to estimate the posterior distributions of the model uncertain variables by matching the primary production data. The McMC process is accelerated by employing an accurate proxy model (kriging) which is updated using a highly adaptive sampling algorithm. Gaussian Processes are then used to optimize the HNP control variables by maximizing the lower confidence interval (μ-σ) of cumulative oil production (after 10 years) across a fixed ensemble of uncertain variables sampled from posterior distributions.
The uncertain variable space includes several parameters representing reservoir and fracture properties. The posterior distributions for some parameters, such as primary fracture permeability and effective half-length, are narrower, while wider distributions are obtained for other parameters. The results indicate that the impact of uncertain variables on HNP performance is nonlinear. Some uncertain variables (such as molecular diffusion) that do not show strong sensitivity during the primary production strongly impact gas injection HNP performance. The results of optimization under uncertainty confirm that the lower confidence interval of cumulative oil production can be maximized by an injection time of around 1.5 months, a production time of around 2.5 months, and very short soaking times. In addition, a maximum injection rate and a flowing bottomhole pressure around the bubble point are required to ensure maximum incremental recovery. Analysis of the objective function surface highlights some other sets of production constraints with competitive results. Finally, the optimal set of production constraints, in combination with an ensemble of uncertain variables, results in a median HNP cumulative oil production that is 30% greater than that for primary production.
The application of a Bayesian framework for optimizing the HNP performance in a real shale reservoir is introduced for the first time. This work provides practical guidelines for the efficient application of advanced machine learning techniques for optimization under uncertainty, resulting in better decision making.
Martins, Ana (Nederlandse Aardolie Maatschappij) | Marino, Marco (Nederlandse Aardolie Maatschappij) | Kerem, Murat (Shell Global Solutions International) | Guzman, Manuel (Shell Global Solutions International)
This paper presents the first comparison between two different injection methods for foam assisted gas lift. Useful information for operators and technology developers are also provided concerning chemical selection, testing, and deployment of this hybrid artificial lift technology in the field.
The trials have been conducted in a gas lifted oil well with severe slugging and water cut above 50% (selection criteria as per SPE-184217-MS). The surfactant was delivered through a dedicated capillary injection string during the first trial, and the effects of surfactant concentration and depth of injection were evaluated. During the second trial, the surfactant was injected into the gas lift stream at the surface. Different surfactants were utilised for both trials based on stability concerns and method of injection.
Both trialled injection methods successfully stabilized the well flow, terminating severe slugging while increasing the drawdown and delivering an increase in gross production of circa 200%. These results, together with the downhole pressure data collected during the first trial, confirm that the surfactant starts foaming only at the depth where the lift gas enters the tubing. Injecting surfactant into the lift gas stream required higher concentrations than using a dedicated injection string, difference attributable to the slightly different chemistry, but even at those higher concentrations an anti-foamer injection was not required.
Concerning the response time, the well responded in 30 to 60 minutes with capillary string injection, while 6 to 12 hours were required for injection into the lift gas stream. This suggests that the surfactant probably moves slowly down on the annulus walls as a liquid film rather than travelling in droplets dispersed in the gas phase. Based on the outcome of the two trials, it is concluded that the injection via the lift gas stream is as effective as capillary string injection, at a fraction of the initial costs, with lower maintenance requirements, while still allowing access to the well.
Relative permeability (kr) functions are among the essential data required for the simulation of multiphase flow in hydrocarbon reservoirs. These functions can be measured in the laboratory using different techniques including the steady state displacement technique. However, relative permeability measurement of shale rocks is extremely difficult mainly because of the low/ultralow matrix permeability and porosity, dominant capillary pressure and stress-dependent permeability of these formations.
In this study, the impacts of stress and capillary end effects (CEE) on the measured relative permeability data were investigated. The steady state relative permeability (SS-kr) measurements were performed on Eagle Ford and Pierre shale samples. To overcome the difficulties regarding the kr measurements of shale rocks, a special setup equipped with a high-pressure visual separator (with an accuracy of 0.07 cc) was used. The kr data were measured at different total injection rates and liquid gas ratios (LGR). In addition, to evaluate the impacts of effective stress, the kr data of an Eagle Ford shale sample were measured at two different effective stresses of 1000 and 3000 psi.
From the experimental data, it was observed that the measured SS-kr data of the shale samples have been influenced by the capillary end effects as the data showed significant variation when measured at different injection rates (with the same LGR). This suggested that the liquid hold-up (i.e. capillary end effects) depends on the competition of capillary and viscous forces. In addition, it was shown that it is more necessary to correct the experimental kr data measured at the lower LGRs. Furthermore, different relative permeability curves were obtained when the kr data were measured at different effective stresses. This behavior was explained as the capillary pressure was expected to be more dominant at the higher effective stress.
The results from this study improve our understanding of unconventional mechanisms in shale reservoirs. It is evident that the behavior of unconventional reservoirs can be better predicted when more reliable and accurate relative permeability data are available. The outcomes of this study will be useful for accurate determination of such kr data.