Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.

To quantify formation damage and understand its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells. Multirate tests can be conducted on both oil and gas wells. In these tests, several stabilized flow rates, qi, are achieved at corresponding stabilized flowing bottomhole pressures, pwf. The simplest analysis considers two different stabilized rates and pressures.

In his book The Nature of Technology, W. Brian Arthur remarked, "The story of this century will be about the clash between what technology offers and what we feel comfortable with." Although Arthur meant this in technology's general sense, the same can be said about the clash between underbalanced drilling (UBD) and managed pressure drilling (MPD). A drilling activity employing appropriate equipment and controls where the pressure exerted in the wellbore is intentionally less than the pore pressure in any part of the exposed formations with the intention of bringing formation fluids to the surface. While the benefits of UBD technology include reservoir damage prevention and increases in production and rate of penetration, users can experience discomfort--mainly from operational and safety standpoints, especially offshore--because the well continuously flows to surface while drilling. It can also be expensive, requiring more complex modeling and prediction of compressible drilling fluids behavior during operation.

In his book The Nature of Technology, W. Brian Arthur remarked, "The story of this century will be about the clash between what technology offers and what we feel comfortable with." Although Arthur meant this in technology's general sense, the same can be said about the clash between underbalanced drilling (UBD) and managed pressure drilling (MPD). A drilling activity employing appropriate equipment and controls where the pressure exerted in the wellbore is intentionally less than the pore pressure in any part of the exposed formations with the intention of bringing formation fluids to the surface. While the benefits of UBD technology include reservoir damage prevention and increases in production and rate of penetration, users can experience discomfort--mainly from operational and safety standpoints, especially offshore--because the well continuously flows to surface while drilling. It can also be expensive, requiring more complex modeling and prediction of compressible drilling fluids behavior during operation.

Despite the drilling industry's shift toward managed pressure drilling (MPD) over the past half-decade, underbalanced drilling (UBD) continues to be a desirable option for many operations today, especially when drilling into pressure-depleted formations and/or attempting to reduce skin damage for better productivity. Because of this sustained demand, largely by operators willing to pay top dollar for skilled UBD personnel, a fundamental knowledge of the technique can benefit young petroleum engineers looking to excel in their field. The philosophy of UBD is diametrically opposed to traditional/conventional drilling methods and MPD. Conventional drilling uses an equivalent mudweight (EMW) that results in a bottomhole pressure (BHP) greater than that of the pore pressure exposed to the open hole to prevent formation fluids (oil, gas, or water) from entering the wellbore. MPD uses equivalent circulating density--a combination of hydrostatic pressure, circulating friction pressure, and applied surface pressure--to create a BHP equal to or greater than formation pore pressure.

The complete paper discusses a method of stimulating deep, high-temperature offshore wells by combining an efficient single-phase retarded acid (SPRA) system and an engineered, degradable, large-sized particulate and fiber-laden diverter (LPFD). The method was introduced in a well in the Arabian Gulf, where it helped the operator achieve effective, uniform stimulation. Treatment of deep, high-temperature carbonate reservoirs such as those in the Arabian Gulf presents a series of complex and related challenges to achieve effective and uniform stimulation. Elevated temperatures and heterogeneous formations in these reservoirs require robust treatment fluids that can withstand the harsh environment to achieve good reservoir contact with an acid system along the entire interval of interest. Emulsified acids have been the preferred stimulation choice of major operators in this region because of these acids' superior corrosion inhibition and deeper penetration into the reservoir.

Automated pattern recognition with basic, high-level coding can be readily applied to petroleum production surveillance to reduce the impact of equipment failure. Machine learning is an application of regression techniques that range in complexity from simple linear regressions to convolutional neural networks. This paper outlines a machine learning based solution that was developed for a common petroleum engineering problem.

A temporary proxy for downhole pressure measurements was developed after gauge failure on an offshore gas production well. A solution was found in the machine learning space by applying multivariate linear regression to represent relationships within the production system. The workflow presented is based on Python code using the open source SKLearn library. Readers should carry out their own independent assessment of the approach outlined in this paper (including the model development procedure pseudo code set out in Appendix B and Python code example set out in Appendix C) in the context of their own specific requirements and circumstances before deciding to use any aspect of the approach (or Python code).

The method uses available production data (known conditions of pressure and temperature from the wellhead and further downstream, choke settings and well total mass flow rates) to predict an unknown downhole pressure. The failure of a downhole gauge was simulated by removing the downhole data from the dataset at a certain point in time. The machine learning model was trained using 19 months of well production data. The nine months that follow was then entered under gauge failure conditions (with downhole data removed), to predict downhole pressure from other production data. The result was a downhole pressure prediction within 0.2% (40 kPa) of the actual gauge measurement up to nine months after the simulated gauge failure.

The prediction was compared to downhole pressure estimations that were calculated with a conventional physical model. The machine learning model outperformed the conventional physical correlation over the test period. The model was validated as an adequate short-term replacement for downhole pressure measurement for an offshore gas well. The solution delayed disruption to the management of reserves, enabled the continuation of production forecasting and postponed subsea intervention.

This paper also provides a foundation for assisted trend analysis, in which a gauge that is identified as drifting from the long-term trend can aid in the detection of physical changes such as water breakthrough.

A new and transformational gas lift method termed Liquid Assisted Gas Lift (LAGL) has been developed. LAGL utilizes the co-injection of liquid with lift gas to reduce surface pressure requirements for the kick-off of gas lift, simplify well completions and improve system reliability/flexibility. PetroleumETC executed a Shell GameChanger project to demonstrate the delivery of LAGL for well unloading and kick-off of gas lift. Qualification testing was performed at a university test facility utilizing a 2,788 ft TVD test well with 5 ½-inch casing and 2 7/8-inch tubing. Air and water were the test media. In-well measurements were available bottomhole and mid-string for both the annulus and the tubing. The test well was successfully unloaded in 2 hours with a maximum pressure of 535 psig using manual operation of the module. Two automated tests were successfully conducted; one requiring 2 hours (670 psig max pressure) and one requiring 1 hr and 24 min (724 max pressure). Many lessons were learned, effectively de-risking the technology for field application. A new sliding-sleeve orifice valve was also tested with water, air and under multiphase flow conditions. The larger orifice sizes provided by the 2 7/8-inch sliding sleeve slim valve provides for faster unloading using the LAGL process. The paper provides an update on advances in the value case for the new LAGL technology. LAGL utilizes a single G-L valve, which reduces system costs versus the traditional use of multiple G-L valves and mandrels and dramatically reduces the risk of multi-pointing. LAGL provides the advantage of High-Pressure Single Point Gas Lift (HPSPGL) without the need for high pressures on the well pad, changing surface piping and a high pressure compressor.

Abstract Flowback rate transient analysis (RTA) is a practical tool for characterizing hydraulic fracture (HF) properties. However, the accuracy of the interpreted results from flowback RTA is challenged by the complexity in two-phase flow in the hydraulic fracture and matrix system. Accordingly, we present a new semianalytical method to characterize HF attributes and dynamics using multi-phase flowback data for tight and ultratight (shale) oil wells. The proposed method includes a two-phase diagnostic plot, a fracture RTA approach for straight-line analysis, and a matrix model capable of characterizing water and oil flow. The RTA approach is based on fracture infinite acting linear flow (IALF) and boundary dominated flow (BDF) solutions, which treats HF as an open tank with a variable production rate at the well and the contribution of water and oil from matrix within the distance of investigation (DOI). The pressure-dependent fluid and geomechanical properties, such as permeability and porosity, are considered in the pseudotime defined in fracture and matrix to reduce the nonlinearity of the system. We tested the accuracy of the proposed method against numerical results obtained from commercial software and verified its applicability by analyzing the flowback and long-term production data from a field example in Eagle Ford shale. The validation results confirm that our method can closely calculate water and oil influx from matrix as well as the average pressure and saturation in the HF and matrix DOI. The accurate estimation of the initial fracture permeability and pore volume demonstrates the applicability of the proposed method in quantifying HF properties from two-phase flowback data exhibiting fracture IALF and BDF regimes. The analysis results show that the estimated initial fracture pore volume shows more accuracy than initial fracture permeability due to the different calculation sources in the straight-line analysis. In short, the proposed method is, to our best knowledge, the first RTA approach incorporating the two-phase water and oil influx from matrix into the inverse analysis of fracture properties and dynamics using straight-line analysis, instead of history matching

Abstract On the example of a gas condensate reservoir of field in Western Siberia with HPHT conditions, high condensate content and low permeability, the problem of reducing well productivity during operation are considered. Restoring of the near wellbore area permeability methods, reduced due to the buildup of retrograde condensate are studied. The effectiveness of previously performed acid treatments and solvent injection has been considered in order to increase the productivity of such wells. The analysis of the ambiguity and variable success of such events is carried out. An unconventional, but promising method of the condensate saturation reducing in the near wellbore areaof wells with multi-stage fracturing is proposed. These wells operate Achimov deposits with HPHT. This method consists of creating special thermobaric conditions in the near wellbore area, which allow to vaporize the largest part of the hydrocarbon condensate accumulated around the borehole. A condensate-saturated gas is extracted from the well to the surface. A search was held for simple, available and inexpensive technologies aimed at increasing both pressure and temperature in the wellbore and near-wellbore region. Based on the results of calculations performed on digital wells models in OLGA software, the thermobaric conditions created at the bottom due to the thermobarochemical effects are determined. The measures effectiveness of the retrograde condensate evaporation in the near wellbore areaand restoration of well productivity have been evaluated.