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2019 Annual Technical Conference and Exhibition - Session 11: Gender Equality in the Oil and Gas Industry - Achieving United Nations Sustainable Development Goal 5
Reid, David (SPE Technical Director-Elect, Drilling) | Dunlop, Johana (SPE Technical Director, HSE & Sustainability) | Ozkan, Erdal (SPE Technical Director, Reservoir) | Moss, Jeff (SPE Technical Director, Drilling) | Palisch, Terry (SPE Technical Director, Completions) | Saadawi, Hisham (SPE Technical Director, Production and Facilities) | Dindoruk, Birol (SPE Technical Director, Management and Information) | Graves, Ramona (SPE Director of Academia)
2019 SPE Annual Technical Conference and Exhibition - Session 9: State-of-the-Technical Discipline - A Conversation with your SPE Technical Directors
Helfenbaum, Bryan (Alberta Innovates) | Bunio, Gary (Suncor Energy) | Romero, Joy (Canadian Natural Resources Limited) | Schilling, Keith (Baker Hughes Canada, a GE company) | Siewe, Cecile (Natural Resources Canada) | Trudell, Cheryl (Imperial)
2019 SPE Annual Technical Conference and Exhibition - Special Session 3: Canadian Innovation and Collaboration Reduces Environmental Impact and Costs
The soft string and stiff string models are different string methods that have been used by the oil industry to calculate torque and drag for years. Opinions have often varied as to which model is better. This paper discusses the intrinsic difference between these two models and proposes a criterion for determining which method would deliver the most accurate results.
Although both the soft string and stiff string models are used for torque and drag calculation, the soft string model is calculated like a soft rope, without considering the influence of the hole size and radial clearance. On the other hand, the stiff string model considers the effect of stiffness, thereby accounting for the extra side contact force. In theory, the stiff string model is more accurate because more variables are considered. However, the field data is more inclined to match the soft string model as opposed to the stiff string model. In fact, many factors, including the stiffness of the string, the shape of the wellbore, and clearance, can influence the status of the string and the value of the contact side force on the string. The present stiff string model does not consider these factors, making it difficult to predict accurate results. This paper analyzes the physics statuses of the string under different scenarios in order to determine which model to apply.
Results demonstrate that borehole tortuosity and the shape of the wellbore can significantly change the status of the string. All factors are relative. A string with a large-size section can be very soft in a straight wellbore, which is fit for a soft string model. Likewise, a string with small-size section can be very stiff in a wellbore with severe tortuosity, which is a better fit for a stiff string model. To accurately estimate the drag force, the stiffness, as well as the wellbore shape and its clearance, should be considered. Extensive simulations have been performed and are reviewed in this paper. Results confirm that the soft string model is a better choice when the string is slimmer, the wellbore is in a lower curvature shape, and the clearance is larger. On the contrary, the stiff string model is more useful when the string is stronger, the wellbore is in a high curvature shape, and the clearance is lower. When to use the models depends on the bending shape of the string in the wellbore. Since neither model is equipped to handle all scenarios, combining the two methods provides better results.
Initial rate and decline are the two main parameters defining the economics of unconventional shale oil development. To improve economics, companies drill longer horizontal wells with more than twenty equidistant stages, different completion strategies and various additives such as surfactants and nano surfactants. This procedure evolves to factory mode in which tasks are optimized in timing and performance without attention to the matrix aspects of improving the recovery. Here, we report the design of a mutual solvent injection pilot in the Vaca Muerta unconventional reservoir during the completion of four unconventional shale oil wells. Reducing
Vaca Muerta has been long regarded as a water wet shale because of the limited water backflow post-fracking job. Alternating water injection was implementing assuming that the well productivity is driven by spontaneous imbibition, but this strategy has been unsuccessful as capillary pressure hysteresis drives this mechanism. We started studying Vaca Muerta from the rock microstructure using energy-dispersive spectrometry and focused gallium Ion Beam ablation FIB SEM images. The microstructure varied widely from millimeters in the same plug which could be expected because in shale rocks millimeters represent more years of deposition than in a conventional reservoir. We identified intercalations of massive water wet zones and strongly oil wet zones in the Vaca Muerta kitchen zone. The oil wet intercalations have high porosity and adsorption isotherm indicating 100 to 1000 times more permeability than the water wet zone. The water wet intercalations are highly saturated with water, and on the contrary, the oil wet intercalations are highly saturated with oil. The pilot designed consisted of four wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, we will estimate the volume contacted by the solvent.
The laboratory protocol indicates a large percentage of macro and meso-pores. We implemented the dimethyl-ether injection which changes the interfacial tension, viscosity and wettability and we obtained the modified relative permeabilities which were the injection of dimethyl ether at 30% concentration along with the hydraulic fracture stimulation stages doubled the initial oil production rate.
The pilot consisted of five wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, using the numerical simulation, we will estimate the volume contacted by the solvent.
Intercalations of high porosity high permeabilities zones in which the injection of a mutual solvent that reduces viscosity and could change wettability in oil wet/water-wet Vaca Muerta improving matrix connectivity.
Karazincir, Oya (Chevron) | Li, Yan (Chevron) | Zaki, Karim (Chevron) | Williams, Wade (Chevron) | Wu, Ruiting (Chevron) | Tan, Yunhui (Chevron) | Rijken, Peggy (Chevron) | Rickards, Allan (Proptester Inc.)
Fracture face permeability loss related to proppant embedment under depletion conditions is one of the factors that contribute to PI decline in hydraulically fractured reservoirs. The damage is a result of proppant embedment and proppant/core crushing that also generates fines and plugs the pores in the embedment zone. A recently developed test method was used to measure the effects of embedment on permeability reduction at the fracture face as a function of depletion, core porosity and permeability, core UCS and injected fluid types. A range of stresses was applied to the cores and the permeability values across the fracture face were tracked and compared.
Standard proppant conductivity tests only measure permeability / conductivity losses within the proppant pack due to frac gel damage and compaction and do not measure the damage at the fracture face.
Recently, we developed a new test method that can directly measure fracture-face permeability under depletion. The test flows fluid from the matrix into the fracture thus coupling permeability measurements within the proppant pack with those across the fracture face. Initial tests were conducted in intermediate permeability, intermediate strength rock. The resulting core permeabilities were compared to the values from conventional core permeability tests. The proppant conductivity values were compared to those measured using a modified API conductivity test set-up. During the second part of this study, a lower permeability, higher UCS rock system was tested and permeability decline was measured as a function of applied stress and flow rate. Cores saturated with different fluid systems were tested to mimic injected fluid imbibition into the fracture face and their effect on proppant embedment and permeability loss. A numerical model was built to calculate fracture face permeability reduction as a function of depletion and injected fluid systems in different types of fractured formations. By incorporating embedment induced permeability reduction into the detailed reservoir geomechanics model, we are able to evaluate the contribution of proppant embedment on overall PI decline. During post-test analysis, proppant embedment percentage and porosity reduction across the fracture face were measured, using Micro CT-scanning, and the damage was also studied using thin section analysis.
Deepwater wells are the most complex and challenging operations for today's petroleum workforce. These challenges push the limits of technology requiring high level personnel competencies and stringent safety requirements. Robust and consistent procedures aid in implementing reliable operational execution. When complex operations include multiple drill ships and TLPs, and when these activities are mirrored by separate support teams of engineers and operations there are opportunities for varying procedures, content, format, and technology applications. This misalignment evolves over time, based on individual preferences, lessons learned, and varying procedures from different service providers.
This paper discusses the efforts and outcomes of bringing standardization to Deepwater operations in the Gulf of Mexico (GOM) and to Shell's broader global Deepwater organization (DWO). Standardization efforts include full End-to-End well delivery from engineering design documents, recommended/best practices, operational procedures, workflow processes, after-action-reviews, knowledge sharing, and refreshing standards as required.
Ensuring a learning loop process is in place and actively used is a key element in keeping standard documents evergreen and has the overarching goal of preventing repeat failures and NPT events. An additional benefit is the ability to deliver documents with structured content, aligned format and standard language to both the operations teams and service providers.
The formation of a core team and central department has driven global standards, active sharing of learnings across all Deepwater business units, opened communication lines with areas previously siloed due to location, reduced cycle time for the engineering teams in re-creating procedures and demonstrated sustainable reductions in operational costs.
While many factors in the reservoir cannot be controlled, there are three controllable factors in field development that make a significant impact. More reservoir contact leads to more oil produced. Controlling sand and water means lower treatment costs, and in-situ reservoir management leads to higher cumulative production. While the underlying technologies have been around for up to 20 years, it is only recently that their synergies and true value are understood. This paper will demonstrate the effect each of these technologies has on increasing overall production rates, improving recovery, and reducing the cost per Barrel of Oil Equivalent (BOE).
The successful implementation of multilaterals in the North Sea will be analyzed. Since 1996, over 300 multilateral junctions have been installed on the Norwegian continental shelf fields with currently approximately 30 junctions completed each year.
Additionally, simulations will be used to demonstrate the incremental improvements in oil recovery that can be obtained by using properly designed advanced completions that include multilaterals, sensors, and passive/active flow control equipment.
The paper will evaluate production performance of a vertical well field development base case against scenarios using horizontal and multilateral wells. It will show how fields can be optimized, leading to increased oil and decreased water production.
Production rates can be significantly improved by combining multilaterals with other advanced completion techniques, such as intelligent completions and inflow control devices. The subject field simulation can be further optimized to manage gas and water production.
With a tailored multilateral field design, combined with properly designed advanced completions systems, the simulation succeeds in terms of achieving maximum contact with the oil reservoir and meeting improved ultimate recovery objectives.
It can be concluded that as reservoir contact is increased, a reduced decline in production rate is observed leading to both a higher Estimated Ultimate Recovery (EUR) and optimized drawdown profile distributions. Additionally, results will be presented that have considered oil production and a method to lower production of unwanted fluids or gas.
This paper also demonstrates the value of field development design from the perspective of reservoir simulation. It is through reservoir insight that a level of understanding is created that can help define the optimum well and completion design to meet field expectations.
Advanced multilaterals continue to grow in popularity with many operators, and it therefore becomes important to evaluate the value of different field development methods. This knowledge can aid operators in unlocking new reservoir targets and optimizing field development, and ultimately will improve recovery factors and overall field economics.
Well diagnostics in deep, offshore GoM are vital in order to interpret any issues related to productivity losses. This is especially important since any intervention in such wells is very costly. Multiphase flow is amongst leading causes of well productivity loss. This paper presents an integrated workflow that provides a solution to the challenge of quantifying multiphase PTA results in single and multiple commingled production cases. The workflow is used to monitor the performance of several wells over an extended period in a deep-water offshore reservoir under water/aquifer drive. It builds on a succession of PTA tests starting from single phase flow until water breakthrough and beyond. The results of historical PTA provided meaningful insights that were used as basis for actions that led to well and reservoir performance optimization.
Water production from oil and gas fields has been more and more increasing globally, and thus the treatment and the reuse of produced water has become one of the top issues in oil and gas industry. Produced water re-injection (PWRI) to reservoirs for pressure maintenance or water flooding is an environmentally-friendly scheme over disposal options. Because solid particles, bacteria, as well as residual oil can cause plugging of the pores in the formation rock resulting in deterioration of oil recovery, PWRI to "tight" or low permeable reservoirs requires high levels of removal of these constituents. In addition, there is also a growing interest of removal of dissolved salts from the produced water for the beneficial reuse. This also requires an advanced filtration as pretreatment to desalination by reverse osmosis (RO) or evaporation. For both of these applications, microfiltration (MF)/ultrafiltration (UF) technologies using ceramic membranes are considered as a very effective solution because ceramic membranes offer high hydrophilicity, relatively low fouling by oil-in-water, and broad chemical and thermal compatibilities. An industrial scale produced water treatment demonstration plant has been installed in an oilfield to test the performance of ceramic MF membranes. The plant includes a crossflow filtration system which accommodates commercial ceramic membranes (180mm Dia., 1,500 or 1,000mmL) followed by RO equipment. The demonstration test was performed for seven months in 2017. Through the seven months of the field demonstration, protocols for sustainable operation were developed under field conditions in which feed water qualities varied very widely in terms of concentration of oil & grease and other foulants. The filtrate contained suspended solids (SS) and oil & grease not higher than 1 mg/l and 10 mg/l, respectively, at all times during the test period. Therefore, it has been proven that the ceramic membrane filtration can be very effective for alleviating plugging risk when applied to PWRI in tight reservoirs. Silt-density-index (SDI) of permeate, an indicator of RO feed water quality was not higher than 3.0 and the average was 1.6; this indicates the membrane-filtered water is appropriate for the RO feed.