ALBERT

Description: Summary Successful reservoir surveillance and production monitoring is a key component for effectively managing any field production strategy. For production logging in openhole horizontal extended reach wells (ERWs), the challenges are formidable and extensive; logging these extreme lengths in a cased hole would be difficult enough but is considerably exaggerated in the openhole condition. A coiled-tubing (CT) logging run in open hole must also contend with increased frictional forces, high dogleg severity, a quicker onset of helical buckling, and early lockup. The challenge of effectively logging these ERWs is further complicated by constraints in the completion where electrical submersible pumps (ESPs) are installed, including a 2.4-in. bypass section. Although hydraulically powered CT tractors already existed, a slim CT tractor with real-time logging capabilities was not available in the market. In partnership with a specialist CT tractor manufacturer, a slim logging CT tractor was designed and built to meet the exceptional demands of pulling the CT to target depth (TD). The tractor is 100% hydraulically powered, with no electrical power, allowing for uninterrupted logging during tractoring. The tractor is powered by the differential pressure from the bore of the CT to the wellbore and is operated by a preset pump rate from surface. Developed to improve the low coverage in openhole ERW logging jobs, the tractor underwent extensive factory testing before being deployed to the field. The tractor was rigged up on location with the production logging tool and run in hole (RIH). Once the CT locked up, the tractor was activated and pulled the coil to cover more than 90% of the openhole section, delivering a pulling force of up to 3,200 lbf. Real-time production logging was conducted simultaneously with the tractor activation; flowing and shut-in passes were completed to successfully capture the zonal inflow profile. Real-time logging with the tractor is logistically efficient and allows instantaneous decision making to repeat passes for improved data quality. The new slim logging tractor (SLT) is the world’s slimmest and most compact and is the first CT tractor of its kind to enable production logging operations in openhole horizontal ERWs. The importance of the ability to successfully log these ERWs cannot be overstated; reservoir simulations and management decisions are only as good as the quality of data available. Some of the advantages of drilling ERWs, such as increased reservoir contact, reduced footprint, and fewer wells drilled, will be lost if sufficient reservoir surveillance cannot be achieved. To maximize the benefits of ERWs, creative solutions and innovative designs must be developed continually to push the boundaries further.

Description: Summary An industry-accepted standard for minifrac analysis for evaluating and improving design of hydraulic fracturing treatments originated from the original Nolte analysis (Nolte 1979) of pressure decline, followed by the introduction of Castillo G-function in a Cartesian plot (Castillo 1987). The latter provides a graphical method for the identification of fracture closure pressures and stresses with subsequent derivation of other parameters such as fluid efficiency and fracture geometry. With the introduction of a more advanced consideration of the G-function interpretation for various reservoir conditions (Barree et al. 2007), subdividing the interpretation into calculations based on flow regimes and leakoff modes, this approach has become even more sophisticated. Particularly, interesting flow regimes and leakoff modes during fracture closure include the fracture height recession mode. This mode tends to result in rapid screenout and difficulty in placing high proppant concentrations. Regarding interpretation, the G-function derivative curve for this mode can have more than one plateau, an outcome that is possibly indicative of features that have not been widely considered to date or on which little to no data have been published. This paper presents a case study as an example of such height recession mode, along with a subsequent G-function interpretation and analysis and with consideration of the vertical facies distribution along the wellbore. Considerable attention is paid to the G-function derivative plateau analysis. Three distinctive wells, namely X-1,X-2, and X-3, are discussed. Using this technique can lead to an improved fracture calibration, optimized fracture design, and adoption of a successful completion strategy; additionally, the confirmation of 1D facies distribution can provide new insights into the fracture closure period.

Description: Summary During the years 2017–2020, when Iran faced restrictions on the sale of oil and gas condensate and due to the need for domestic consumption and gas sales commitments, it was inevitable to produce gas at full capacity. This coercion has led to significant production of gas condensates. Some of these condensates were sold, some were converted into products such as gasoline in domestic refineries, and some of these condensates needed to be stored, but the storage capacity was limited. For the purpose of underground condensate storage, a heavy oil reservoir was selected based on some technical and operational criteria. A feasibility study was conducted to evaluate the potential risks of condensate injection into the reservoir. The results of tests on asphaltene precipitation, as the most important risk, indicated no severe precipitation would occur even if high concentration of condensate mixed with the reservoir heavy oil. The recovery of condensate and the production performance of the reservoir were simulated in three different injection-production scenarios. The results showed a positive effect of condensate injection on production rate of the reservoir. Moreover, satisfactory volume of condensate could be recovered in a reasonable period of time.

Description: Summary Multistage plug-and-perforate fracturing of horizontal wells has proved to be an effective method to develop unconventional reservoirs. Various studies have shown uneven fluid and proppant distributions across all perforation clusters. It is commonly believed that both fracturing fluid and proppant contribute to unconventional well performance. Achieving uniform fluid and proppant placement in all perforation clusters is an important step toward optimal stimulation. This paper discusses how to achieve such uniform placement in each fracturing stage by means of a computational fluid dynamics (CFD) modeling approach. A laboratory-scale CFD model was built and calibrated using experimental data of proppant transport through horizontal pipes available from several laboratory configurations. A field-scale model was then built and validated using perforation erosion data from downhole camera observations. With the field-scale model validated, CFD simulations were performed to evaluate the impact of key parameters on fluid and proppant placement in individual perforations and clusters. Some key parameters investigated in this study included perforation variables (orientation, size, and number), cluster variables (count and spacing), fluid properties, proppant properties, pumping rates, and stress shadow effects. Both laboratory and CFD results show that bottom-side perforations receive significantly more proppant than top-side perforations because of gravitational effects. Laboratory and CFD results also show that proppant distribution is increasingly toe-biased at higher rates. Proppant concentration along the wellbore from heel to toe varies significantly. Gravity, momentum, viscous drag, and turbulent dispersion are key factors affecting proppant transport in horizontal wellbores. This study demonstrates that near-uniform fluid and proppant placement across all clusters in each stage is achievable by optimizing perforation/cluster variables and other treatment design factors. CFD modeling plays an important role in this design-optimizationprocess.

Description: Summary The impacts of formation layering on hydraulic fracture containment and on pumping energy are critical factors in a successful stimulation treatment. Conventionally, it is considered that the in-situ stress is the dominant factor controlling the fracture height. The influence of mechanical properties on fracture height growth is often ignored or is limited to consideration of different Young’s moduli. Also, it is commonly assumed that the interfaces between different layers are perfectly bounded without slippage, and interface permeability is not considered. In-situ experiments have demonstrated that variation of modulus and in-situ stress alone cannot explain the containment of hydraulic fractures observed in the field (Warpinski et al. 1998). Enhanced toughness, in-situ stress, interface slip, and energy dissipation in the layered rocks should be combined to contribute to the fracture containment analysis. In this study, we consider these factors in a fully coupled 3D hydraulic fracture simulator developed based on the finite element method. We use laboratory and numerical simulations to investigate these factors and how they affect hydraulic fracture propagation, height growth, and injection pressure. The 3D fully coupled hydromechanical model uses a special zero-thickness interface element and the cohesive zone model (CZM) to simulate fracture propagation, interface slippage, and fluid flow in fractures. The nonlinear mechanical behavior of frictional sliding along interface surfaces is considered. The hydromechanical model has been verified successfully through benchmarked analytical solutions. The influence of layered Young’s modulus on fracture height growth in layered formations is analyzed. The formation interfaces between different layers are simulated explicitly through the use of the hydromechanical interface element. The impacts of mechanical and hydraulic properties of the formation interfaces on hydraulic fracture propagation are studied. Hydraulic fractures tend to propagate in the layer with lower Young’s modulus so that soft layers could potentially act as barriers to limit the height growth of hydraulic fractures. Contrary to the conventional view, the location of hydraulic fracturing (in softer vs. stiffer layers) does affect fracture geometry evolution. In addition, depending on the mechanical properties and the conductivity of the interfaces, the shear slippage and/or opening along the formation interfaces could result in flow along the interface surfaces and terminate the fracture growth. The frictional slippage along the interfaces can serve as an effective mechanism of containment of hydraulic fractures in layered formations. It is suggested that whether a hydraulic fracture would cross a discontinuity depends not only on the layers’ mechanical properties but also on the hydraulic properties of the discontinuity; both the frictional slippage and fluid pressure along horizontal formation interfaces contribute to the reinitiation of a hydraulic fracture from a pre-existing flaw along the interfaces, producing an offset from the interception point to the reinitiation point.

Description: Summary The objective of this study is the experimental and theoretical investigation of the fall mechanics of continuous flow plungers. Fall velocity of the two-piece plungers with different sleeve and ball combinations and bypass plungers are examined in both static and dynamic conditions to develop a drag coefficient relationship. The dimensionless analysis conducted included the wall effect, inclination, and the liquid holdup correction of the fall stage. A fall model is developed to estimate fall velocities of the ball, sleeve, and bypass plungers. Sensitivity analysis is performed to reveal influential parameters to the fall velocity of continuous flow plungers. In a static facility, four sleeves with different height, weight, and outer diameter (OD); three balls made with different materials; and a bypass plunger are tested in four different mediums. The wall effect on the settling velocity is defined, and it is used to validate the ball drag coefficient results obtained from the experimental setup. Two-phase flow experiments were conducted by injecting gas into the static liquid column, and the liquid holdup effect on the drag coefficient is observed. Experiments in a dynamic facility are used for liquid holdup and deviation corrections. The fall model is developed to estimate fall velocities of the continuous flow plungers against the flow. Dimensionless parameters obtained in the experiments are combined with multiphase flow simulation to estimate the fall velocity of plungers in the field scale. Reference drag coefficient values of plungers are obtained for respective Reynolds number values. Experimental wall effect, liquid holdup, and inclination corrections are provided. The fall model results for separation time, fall velocity, total fall duration, and maximum flow rate to fall against are estimated for different cases. Sensitivity analysis showed that the drag coefficient, the weight of plungers, pressure, and gas flow rate are the most influential parameters for the fall velocity of the plungers. Furthermore, the fall model revealed that plungers fall slowest at the wellhead conditions for the range of gas flow rates experienced in field conditions. Lower pressure at the wellhead had two opposing effects; namely, reduced gas density, thereby reducing the drag and gas expansion that increased the gas velocity, which in turn increased the drag. Estimating fall velocity of continuous flow plungers is crucial to optimize ball and sleeve separation time, plunger selection, and the gas injection rate for plunger-assisted gas lift (PAGL). The fall model provides maximum flow rate to fall against, which is defined as the upper operational boundary for continuous flow plungers. This study presents a new methodology to predict fall velocity using the drag coefficient vs. Reynolds number relationship, wall effect, liquid holdup, deviation corrections, and incorporating multiphase flow simulation.

Description: Summary Gerotors are positive displacement pumps and potential artificial lift options in the oil and gas industry. This study presents the performance characteristics from physical testing of a unique one-stage, equal-walled gerotor pump design operating in oil and oil/air mixtures. The pump was tested at various rotational speeds in a flow loop. The performance results were obtained to ascertain potential design optimizations of the pump before embarking on manufacturing and testing of the field prototype pump. A physical prototype of a one-stage 400 series gerotor pump, suitable for application in a 5.5-in. casing, was designed, manufactured, assembled, and tested. Mineral oil and air were used as the operating media. For given pump outlet valve settings, the pump rotational speeds were set to 200, 250, 300, and 350 rev/min. Gas volume fractions (GVFs) at the pump inlet were varied from 0% to the maximum the current pump design could handle. For each test point, the corresponding pump parameters were measured. Dimensionless performance plots were established for obtaining pump performance at other flow conditions. The results showed that pump flow rate decreased with increasing differential pressure, typical of positive displacement pumps. At 200 and 350 rev/min, maximum pump delivery is approximately 190 and 330 B/D of oil, respectively, at zero differential pressure. The pump can supply flow against a differential pressure of up to approximately 5.5 psi at 200 rev/min and 15 psi at 350 rev/min. For the 200 to 350 rev/min speed range, volumetric efficiencies varied from 30 to 73%, whereas the electric power input varied from 145 to 191 W. When pumping oil/air mixtures, the current gerotor pump design can handle 15% GVF maximum, at 250, 300, and 350 rev/min. For certain pump outlet pressures, the total fluid flow rates decreased as the GVF increased to 15%. The volumetric efficiencies at 15% GVF varied from 32 to 53% for the 300 to 350 rev/min speed range, whereas the motor electric power input decreased with increasing GVF up to 15%. In conclusion, increasing the pump rotational speed improves the volumetric efficiency and gas-handling capability of the gerotor pump. These observations will aid in the required design optimization to enhance the performance of the future field prototype gerotor pump. This study presents the capabilities of gerotors as potential artificial lift alternatives to handle liquid and gas/liquid mixtures for boosting applications in oilfield operations. The technology with additional design optimization can be readily integrated into oilfield equipment architecture. The mechanical simplicity of gerotors and their compactness provides a promising artificial lift substitute that may be implemented for downhole or surface production of liquid or gas/liquid mixtures in the oil and gas industry.

Description: Summary One of the enduring pieces of the jigsaw puzzle for all unconventional plays is drawdown (DD), a technique for attaining optimal return on investment. Assessment of the DD from producing wells in unconventional resources poses unique challenges to operators; among them the fact that many operators are reluctant to reveal the production, pressure, and completion data required. In addition to multiple factors, various completion and spacing parameters add to the complexity of the problem. This work aims to determine the optimum DD strategy. Several DD trials were implemented within the Anadarko Basin in combination with various completion strategies. Privately obtained production and completion data were analyzed and combined with well log analysis in conjunction with data analytics tools. A case study is presented that explores a new strategy for DD producing wells within the Anadarko Basin to optimize a return on investment. We use scatter-plot smoothing to develop a predictive relationship between DD and two dependent variables—estimated ultimate recovery (EUR) and initial production (IP) for 180 days of oil—and introduce a model that evaluates horizontal well production variables based on DD. Key data were estimated using reservoir and production variables. The data analytics suggested the optimal DD value of 53 psi/D for different reservoirs within the Anadarko Basin. This result may give professionals additional insight into more fully understanding the Anadarko Basin. Through these optimal ranges, we hope to gain a more complete understanding of the best way to DD wells when they are drilled simultaneously. Our discoveries and workflow within the Woodford and Mayes Formations may be applied to various plays and formations across the unconventional play spectrum. Optimal DD techniques in unconventional reservoirs could add billions of dollars in revenue to a company’s portfolio and dramatically increase the rate of return, as well as offer a new understanding of the respective producing reservoirs.

Description: Summary Well surveillance requires practical models to balance the reward of maximizing production with the risk of ramping up production too much, which damages the completion. In this paper we present a method to monitor and ramp up production for openhole standalone screen (OH-SAS) completion. The objective is to optimize production using pressure transient analyses to assess the completion impairment and failure risks during the production ramp-up process. The flux model incorporates filter-cake pinholes, which are formed from nonuniform deposition and cleanup of filter cake during drilling and completion operations. Pinholes cause concentrated fluxes and increase completion failure risks. The method comprises three components, which are (1) determine pinhole properties from laboratory tests, (2) relate completion pressure drop of production through pinholes to pressure transient analyses, and (3) distribute fluxes in the standalone screen wellbore. Examples are presented and show that the completion pressure drop as a function of flow rate is nonlinear and higher with pinholes than without pinholes. By not incorporating pinholes, operations can potentially limit ramp-up. Flux distribution examples show that the largest impingement or radial velocity is at the top section of screen. The axial annular flow velocity or scouring velocity is two orders of magnitude larger than the screen impingement velocity. An integrated flux surveillance method for OH-SAS completion is presented for field applications.

Description: Summary It is common to inject acidic stimulation fluids into oil-bearing carbonate formations to enhance well productivity. This process of matrix acidizing is designed to maximize the propagation of wormholes into the formation by optimizing the injection parameters, including acid-injection rate and volume. Previous studies have suggested that saturation conditions, permeability, heterogeneity, temperature, and pressure can significantly affect the design of matrix-acidizing treatments. However, laboratory studies’ results are inconsistent in their conclusions and are mostly limited to water-saturated cores. In this work, we designed a systematic experimental study to evaluate the impact of multiphase flow on the acidizing process when injecting 15 wt% hydrochloric acid (HCl) into crude-oil-saturated Indiana Limestone cores. The results reveal the following: Contrary to published literature for water-saturated cores, acidizing in partially oil-saturatedhigh-permeability cores at high pressure requires less acid volume than in low-permeability cores; lower-pressure acid injection results in more efficient wormhole propagation in low-permeability cores compared to high-pressure acid injection; acidizing in low- and high-permeability cores at low pressure leads to similar efficiency; and wormholing is more effective in partially oil-saturated cores, resulting in multiple parallel branches as compared to inefficient leakoff in water-saturatedcores.