Attempts had been made by many authors to develop an inflow performance relationship model suitable for solution gas drive reservoirs. However, they have not been as successful as most of the developed models suffer from certain degrees of inaccuracies and this necessitates the need for an improved model as the economic analysis of an oilfield greatly depends on the ability to accurately forecast future productions. Therefore, the objective of this research is to develop an improved inflow Performance Relationship model for solution gas reservoirs by employing a purely analytical approach and also compare the performance of the developed model with that of the existing IPR models (Vogel, Wiggins, Fetkovich, and Klins and Majher). A series expansion of the pseudo-steady state solution of the equation that governs fluid flow in reservoirs of radial geometry is obtained using Taylor's method and the infinite series obtained is truncated after a reasonable number of terms to ensure high degree of accuracy while also avoiding computational complexity. Moreover, the unknown coefficients in the truncated series were determined using the available reservoir fluid data. Finally, statistical analysis was carried out to determine the degree of deviation of the new and existing IPR models from the actual IPR. This analysis shows that the improved model (with an average coefficient of determination of 0.97) outperforms the existing IPR models to which it was compared. Therefore, the improved model is recommended for situations where extreme accuracy is of utmost importance. Doi: 10.28991/HEF-2021-02-02-04 Full Text: PDF

Microneedles are a new technology for percutaneous drug delivery. They are often conveyed in a series of multiple simple microneedles used on the skin to facilitate systemic or topical drug delivery. They are manufactured using various techniques and they could be hollow, solid, coated or polymeric. Although classified as an emerging but expanding field of drug delivery, they are flawed in many ways. This paper will extensively discuss (in the context of skin physiology) the use of microneedles and their feasibility in delivering medication to sites of actions in the body. This paper is a review paper and data were collated from multiple sources including journals and articles. Microneedles show great potential; however, the physiology of the skin poses a great challenge for researches in this field.

Summary Distributed acoustic sensing (DAS) is an emerging surveillance technology that is becoming increasingly popular in the oil and gas industry for real-time flow monitoring. However, there are limited studies that rigorously quantify flow rates using DAS. This work expands the existing literature by presenting a detailed workflow for accurately estimating fluid flow rates from DAS data using time- and frequency-domain signal processing. Three simple empirical correlation functions (linear, exponential, and cubic) are developed and tested to predict flow rates from DAS. The proposed correlations are demonstrated for flow rates ranging from 50 to 300 gallons per minute (GPM) in a vertical 5,163-ft-deep wellbore and from 12 to 36 GPM in a horizontal surface flow loop. Tests were performed using a single-phase flow of water as well as using synthetic oil-based drilling mud. Time-domain DAS processing using root-mean-square (RMS) value and frequency-domain processing using frequency band energy (FBE) is evaluated, followed by a statistical approach to minimize the influence of outliers. The RMS and FBE approaches are individually compared for flow prediction, and the performance of the correlations is rigorously evaluated on a blind data set that was not originally used for developing the correlations. For both the wellbore and flow loop data sets, a coefficient of determination (or R2) greater than 0.95 with an average flow rate prediction error of less than 10% was achieved for the best-performing correlation for the blind test data. The analysis procedure and workflow presented in this study can be adopted and extended to different operating conditions for quantitative flow rate prediction using DAS.

Accurate estimation of compressibility factor is of great importance in predicting the performance of gas reservoirs using the material balance approach and also in the designing of gas pipelines and flowlines. Over the years, several correlations for estimating gas compressibility factor have been developed. However, these correlations have not been so successful in predicting the compressibility factor for High pressure-High temperature (HPHT) reservoirs and this explains why the industry still relies on the expensive and time-consuming constant volume depletion (CVD) approach. Therefore, this paper presents a correlation suitable for estimating the compressibility factor for high pressure-high temperature (HPHT) reservoirs using stochastic and robust optimization approach with Gaussian probability distribution. The results obtained shows that the correlation outperforms other pre-existing correlations within the range of pressures and temperatures considered.

Summary Conventional methods of managing gas-in-riser events are not optimal when the drilling riser is isolated from the formation by a closed subsea blowout preventer (BOP) on rigs equipped with mud gas separator (MGS), managed pressure drilling (MPD), or riser gas-handling equipment. The industry is concerned about exceeding the pressure limit of the riser and the flow capacity of the MGS and hence has not been able to reach a consensus on a circulation method for riser gas. This work is an analysis of the first-ever demonstration of the fixed-choke constant-outflow (FCCO) circulation method in synthetic-based mud (SBM) carried out in June 2022. The first-ever demonstration of the FCCO circulation method in water was performed in March 2021. The results from the water tests were discussed in IADC Gas-in-Riser/Riser Gas-Handling Subcommittee meetings, and the new fixed-choke method was named FCCO in November of 2021. The reason for using the acronym FCCO for the new method is that it allows the use of a fixed-choke opening percentage throughout the circulation period by managing the outflow and backpressure by varying only the pump rate. This work includes the comparison of the actual test results from the March 2021 FCCO tests in water with results estimated using a new model. This is followed by a discussion of the results from the June 2022 FCCO test in SBM. Nitrogen gas was injected into the bottom of an annulus 5,200-ft deep, vertical test well (9 5/8×2 7/8 in. casing/tubing) initially filled with water and instrumented with four downhole pressue and temperature gauges, and distributed fiber-optic sensors [distributed temperature sensing (DTS) and distributed acoustic sensing (DAS)] for water tests, and later filled with SBM. We started direct circulation to produce flow out of the annulus through a choke kept at a fixed open position (%) required for a preplanned applied surface backpressure (ASBP). We reduced pump rate if/as necessary to maintain this ASBP to ensure outflow rate within MGS flow capacity. We performed tests at different fixed-choke positions, different average ASBPs, and initial pump rates. We tested constant bottomhole pressure (CBHP) circulation and fixed pump rate methods also for comparison with the FCCO circulation method. The results from the FCCO tests demonstrated better control of outflow compared with the other methods. There is no need to use high ASBP. The use of a high ASBP suppressed the value of peak pressure. Installation of more than one gauge inside the riser enhances safety by allowing real-time influx detection capability, estimation of gas position, gas velocity, and gas void fraction. The FCCO method can be preplanned and easily substituted as the preferred circulation method for staying within the handling capacity of the existing MGS on the rig during gas-in-riser situations.