Production and Well Operations

The objective of this work is to demonstrate that the choice of the conveyance method for Production Logging operations is key in horizontal wells, as it affects the flow dynamics and changes the well inflow performance compared to undisturbed flowing conditions. A case study is presented, showing that critical decisions to develop a field (or not) may have been wrongly influenced by Production Logging results, if the effects of the conveyance on the inflow distribution were not correctly understood.

Synthetic production logs and flowing pressure distributions along the horizontal section were computed, and sensitivities on conveyance method diameter (coiled tubing, tractor and cable), pipe diameter, well length and reservoir properties were also conducted. These results were compared with the normal well flowing conditions to establish the representativeness of the PL measurements. A method for simulating the undisturbed production profile is presented, which uses the results of a Multirate Production Logging and recomputed flowing pressures using nodal analysis.

The presence of the conveyance method alters the well's inflow performance and zonal contributions, due to the modifications of the flow geometry and additional frictional pressure drop. The bottomhole flowing pressure is disturbed, with lower pressures around the heel and higher towards the toe. The drawdown along the horizontal gets modified, acting as a preferential choke for production coming from the toe and increasing the driving force for production from the heel. The severity of the drawdown unbalance is a function of the induced frictional pressure, given by the pipe and conveyance diameter, well length, flow rates, etc. The simulations and sensitivities presented in this paper help to understand how significant the PL measurements are, and when these results become misleading. The case study supports these findings, where the pressure disturbance induced by the conveyance changed the flow distribution dramatically, wrongly indicating than an area of the field was relatively depleted compared to the zone around the heel. The lack of understanding of the impact of the conveyance method can lead to poor developmental decisions.

The application of real - time monitoring technologies presents a means to harnessing proactive or reactive controls in minimizing severity effects of slugging in the production system. This paper presents the development of a non-intrusive optical infrared sensing (NIOIRS) setup, for slug monitoring in pipes. The flow characteristics monitored were the development of slug flows and average phase fractions of gas and liquid in a vertical test section (0.018m by 1m) for superficial velocities of 0-0.131 m/s for water and 0 – 0.216 m/s for air. The measurement principle was based on the disparities in refractive indices of each phase in the sensing area. The sensing component of the sensor consisted of two pairs of IR emitters and photodiodes operated at wavelengths of 880 nm specifications. A circuit, for signal conditioning, amplification and data acquisition was set up to convert infrared light detected into voltage signals. Development of slug flow regimes was monitored from signal distributions binned under reference voltages. The transitions from bubble to slug flow, were observed at 10 percent count ratios of the signal distributions around typical sensor reponse for air. Validation from photos showed good agreements with the sensor response. A single peaked distribution around the reponse for water indicated bubble flow regimes, with the development of two peaks indicated increasing gas slugs for increasing superficial gas velocities compared to liquid slug in the pipe. Phase fraction results were interpreted from a derived calibration model, which was based on the average observed voltage and reference voltages of water and air over time. This model was compared with swell level changes, photographs and homogenous and drift flux correlation with agreement within +/-2 % for all flow regimes observed in the pipe. The Real-time application was carried out via the execution of an algorithm which incoprated the calibration information from the NIOIRS. The derived signals were processed and analysed onto a display in identifying slug flows development and phase fractions in real-time. A cheap and accurate sensing setup has been developed with the potential of real time monitoring of flow regimes and phase fraction detemination.

Curved pipes are essential components of subsea process equipment and some part of production pipeline and riser. So far, most of the studies on of wax deposition and the possible mitigation strategies have been carried out using straight pipelines, with little attention given to curved pipes. Therefore, the objective of this study is to use an experimental flow loop designed and assembled in the lab to study and understand the mechanisms and variable parameters that affect wax depositional behaviour under the single-phase flow. Series of experiments were carried out with pipes curvatures of 0, 45 and 90-degree at different flow rates (2 and 11 L/min). The sequence in which the bends are incorporated creates non-uniformity of boundary shear, flow separation, and caused isolation of fluid around the bends that affect wax deposition, which depends on flow regimes – Reynolds number along with the radius of curvature of the bend. Prior to the flow loop experiment, the waxy crude oil was characterized by measuring the viscosity, WAT (30°C), pour point (25.5°C), n-Paraffin distribution (C10 - C67), and the saturated/aromatic/resin/asphalte (SARA) fractions

Results of this study shows that the wax deposit thickness decreases at higher flow rate within the laminar (Re<2300) and turbulent (Re>2300) flow regimes. It was observed that the deposition rate was significantly higher in curved pipes, about 8 and 10% for 45 and 90-degree, respectively in comparison to the straight pipe for all flow conditions. Increase elevation of the curved pipe, however, led to a more wax deposition trend; where a higher percentage of wax deposit was observed in 45-degree compared to 90-degree curved pipe. This trend was due addition of gravity forces to the frictional forces - influenced by the physical mechanisms of wax deposition mainly molecular diffusion, shear dispersion and gravity settling. From the results of this study, a new correlation between wax deposit thickness and pressure drop was developed. A relationship was established between wax deposit thicknesses, bend angle in pipes and wax deposition mechanisms with a reasonable agreement with published data, especially for steady state condition. Therefore, this study will enhance the understanding of the wax deposition management and improve predictions for further development of a robust mitigation strategy.

The paper provides analytical and semi-analytical solutions to predict the temperature transient behavior of a vertical well producing slightly compressible fluid under specified constant-bottom-hole pressure or rate in a two zone, radial composite no-flow reservoir system, where the inner zone could represent the skin zone, whereas the outer zone represents non-skin zone. The solutions are obtained by solving the decoupled isothermal diffusivity equation for pressure and thermal energy balance equation for temperature for the inner and outer zones by using the finite-difference and Laplace transformation. They be used to simulate temperature transient behavior for the general cases of specified variable bottom-hole or rate production represented by piecewise constants in specified time intervals. The convection, conduction, transient adiabatic expansion and Joule-Thomson heating effects are all considered in solving the temperature equation. Graphical analysis procedures for analyzing such temperature transient data jointly with pressure or rate transient data are also discussed. The results show that sandface temperature first decreases due to adiabatic expansion and then increases due to Joule-Thomson heating for both constant rate and constant bottomhole pressure production cases during infinite-acting flow. During boundary dominated flow, sandface temperature decreases linearly with time due to pore-volume expansion of the fluid over the entire no-flow reservoir system. The time rate of decline is governed by the ratio of the adiabatic-expansion coefficient of the fluid to the volumetric heat capacity of the saturated medium and the pore volume. However, these flow regimes are not well-defined for the constant bottomhole production case because the sandface rate decreases continuously during the infinite-acting radial flow and boundary dominated flow periods and distorts the flow regimes which are well defined on the temperature behavior if the well were produced at a constant rate. Sandface temperature data under specified variable rate or bottom-hole pressure show complicated behaviors and require more general automated history matching methods based on simultaneous use of both sandface temperature and rate transient data sets for parameter estimation.

EBN is the Dutch state energy company that is a large non-operating partner of over 10 different operators that produce from more than 200 on- and offshore assets with more than 850 projects defined on them. Estimating budget production, medium and long-term forecasts and its associated operating and capital expenditures are of vital importance to EBN. Larger companies with many assets and even more projects, at varying degree of maturity, have great difficulty to reliably predict an aggregated forecast.

Historically, EBN would copy and risk operator data, which led to continuous overestimation of both budget production and longterm forecasts. A straightforward correction method was developed; that consists of two parts: firstly, the budget production is set for all producing assets and projects by assessing technical, subsurface, infrastructural and human factors on the operator's fields and projects performance. Secondly, the medium and longterm forecast is delayed with 1 to 4 years for respective SPE PRMS resource classes "justified for development" to "project unviable" and the associated project forecasts are risked with a chance of development according to their subclasses of the contingent resource classes.

Data analytics on almost 10 years of reserve reporting according to SPE PRMS standards led to a straightforward solution to reduce short and medium-term forecasting error. The short-term absolute average error used to be 8%. Through the implementation of the new method, 7 years ago, the absolute average short-term forecasting error dropped to 4%. The long-term aggregated forecast, obtained by simply copying the operator data, resulted in an overestimation of up to 50% 5 years ahead. The overestimation was reduced to an absolute average error of 23% by an earlier correction method, which only used risking factors on contingent projects, but no time delay. This paper presents a new method, that uses both risking factors and time delays on the realization of projects. The method reduced the error in the long-term forecast to an uncertainty band of a few percent.

Various causes for the overestimation were identified. The budget production errors were primarily attributed to wrong uptime predictions. Longterm forecast errors are impacted by the overestimation of the number of executed projects, while the timing and performance of new projects affects both the short and middle term forecasts.

The solution presented is the first methodology for EBN that is able to predict aggregated forecasts of hundreds of projects of several operators with an accuracy within a 5% margin over a lengthy period. The described risking factors described, and delay times, are dependent on the portfolio maturity and investment climate. Historic data has to be utilized to determine these factors for your portfolio.

The aim of this paper is to compare the performance of three horizontal infill wells in a mature field, of which one is completed with autonomous inflow control devices (AICDs). The analytic results are based on the comparison of oil production rates; water cut development and water-oil ratio plots of the wells. All the wells in this study are producing from the same homogeneous sandstone reservoir.

Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production of which one of these wells is completed with slotted liners and the other with AICDs. Both are artificially lifted with high rate electrical submersible pumps (ESPs). The third horizontal well was placed in an area with higher gas saturation, where a completion with casing, cementation and perforation was used. The performance of the horizontal wells is compared against each other.

The use of active geo-steering successfully supported the well placement into the "sweet spot" of the reservoir due to real-time well path adjustments.

It was found that the AICDs choke back a high amount of fluid and keep the water cut at a stable plateau level. This observation underlines the key benefit of using AICDs as when comparing to the other producing wells without AICDs, the water cut is steadily increasing.

Therefore the use of AICDs is a real option for horizontal well completion.

This paper will be useful to those who are in a phase of early well planning, e.g. in a field (re-)development project and have to select the best well concept (e.g. slotted liner vs. AICDs). AICDs have proven their value even in a super-mature oil field by improving production. Further advantages and challenges during operation are discussed in this paper.

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.

Liquid loading phenomenon is known as the inability of the produced gas to carry all the co-produced liquid to the surface. Under such condition, the non-removed liquid accumulates at the wellbore resulting in reduction of the production and sometimes cause the death of the well. Several studies were carried out and correlation were developed based on field and experimental data with the aim to predict the onset of liquid loading in a gas well. However, each model provides different indication on the critical gas velocity at which the liquid loading exists. Thus, to have a clear understanding on the difference between most used models, experiments were performed in an upward inclinable pipe section. The 60-mm diameter test pipe was positioned at angles of 30°, 45° and 60° from horizontal. The fluids used were air and light oil. Measurements include fluid velocities and fluid reversal point. High-speed video cameras were used to record the flow conditions in which the onset of liquid loading initiated. Experimental results were compared with existing models by Turner et al. (1969), Barnea (1986), Belfroid et al. (2008), Luo et al. (2014), Shekhar et al. (2017) and with a commercial dynamic multiphase flow simulator from SPT-Group (OLGA2017.1.0®). Prediction using the liquid film models presented acceptable agreement with experimental.

A waterflood study has been performed on a heterogeneous oil deposit with a rising water-cut and production decline after 10 years of commercial production.

Engineers need to predict the production characteristics from hydraulically fractured wells in tight gas fields. Decline curve analysis (DCA) has been widely used over many years in conventional oil and gas fields. It is often applied to tight gas, but there is uncertainty regarding the period of production data needed for accurate prediction.

In this paper decline curve analysis of simulated production data from models of hydraulically fractured wells is used to to develop improved methods for calibrating decline curve parameters from production data. The well models were constructed using data from the Khazzan field in Oman. The impact of layering, permeability and drainage area on well performance is also investigated. The contribution of each layer to recovery and the mechanisms controlling that contribution is explored.

The investigation shows that increasing the amount of production data used to fit a hyperbolic decline curve does not improve predictions of recovery unless that data comes from many years (20 years for a 1mD reservoir) of production. This is because there is a long period of transient flow in tight gas reservoirs that biases the fitting and results in incorrect predictions of late time performance. Better predictions can be made by estimating the time at which boundary dominated flow is first observed (t_b), omitting the preceding transient data and fitting the decline curve to a shorter interval of data starting at t_b. For single layer cases, t_b can be estimated analytically using the permeability, porosity, compressibility and length scale of the drainage volume associated with the well. Alternatively, t_b can be determined from the production data allowing improved prediction of performance from 2-layer reservoirs provided that a) there is high cross-flow or b) there is no cross-flow and the lower permeability layer either does not experience BDF during the field life time or it is established quickly.