Flow Wellhead Pressure Research Articles

Transient Wellbore-Pressure-Buildup Correlation Helps Engineers To Ensure HIPPS Safe Operation

Summary The objective of this study is to develop a correlation for transient wellbore-pressure buildup and relate it to the high-integrity pressure-protection system (HIPPS) response time in multiphase flow. The developed correlation gives an accurate estimate of the pressure buildup with time under shut-in conditions. It provides guidelines to set the HIPPS activation pressure considering different reservoir and wellbore parameters to ensure the safety and timely response of HIPPS. The correlation was developed by performing transient simulations to calculate the wellbore-pressure-buildup time under shut-in conditions accounting for different reservoir and wellbore parameters. The input data were gathered from three oil fields with various fluid properties, reservoir pressures, productivity indices (PIs), depths, and shut-in wellhead pressures (SIWHPs). Before feeding the data to the dynamic flow simulator, the reservoir data were tuned to match the well-flow conditions. After completing the transient simulation for every well, the pressure-buildup data as a function of time were collected and used as input to develop a correlation using the nonlinear-regression method. The results of this study show that the most influential parameters on the pressure-buildup behaviors are fluid compressibility, PI, flowing wellhead pressure (FWHP), and well measured depth (MD). In addition, we observed that there is a strong relationship between the fluid compressibility at FWHP condition and the time it takes to pressurize the wellbore to maximum pressure. The higher the fluid compressibility, the longer it takes the system to pressurize. The newly developed correlation provides a guideline for setting the HIPPS activation pressure and ensuring the wells’ safe operation.

Investigation of the Conditions Required for Improved Oil Recovery by an Earthquake

Summary This study aims to clarify a phenomenological relationship between earthquakes and temporarily improved oil recovery for a small oil field located in a seismically active region of Japan. Our study concludes that the conditions required for an earthquake to temporarily improve oil recovery in this field are as follows: An earthquake with a seismic intensity of at least 3 hits the well. The well experiences a decline in productivity, with a flowing wellhead pressure of less than 690 kPaa (100 psia). The corresponding skin factor lies within the range of 18 to 40. The well is producing oil from a reservoir.

Estimation of oil and gas properties in petroleum production and processing operations using rigorous model

ABSTRACTWellhead chokes are widely used in the petroleum industry. Owning to the high sensitivity of oil and gas production to choke size, an accurate correlation to specify choke performance is vitally important. The aim of this contribution was to develop effective relationships among the liquid flow rate, gas liquid ratio, flowing wellhead pressure, and surface wellhead choke size using the support vector machines (SVMs). The accurate data set was gathered from the 15 different fields containing 100 production samples from the vertical wells at wide ranges of wellhead choke sizes. This computational model was compared with the previous developed correlations in order to investigate its applicability for subcritical two phase flow regimes through wellhead chokes. Results confirmed amazing capability of the SVM to predict liquid flow rates. The value of R2 obtained was 0.9998 for the SVM model. This developed predictive tool can be of massive value for petroleum engineer to have accurate estimations of liquid flow rates through wellhead chocks.

Surface Jet Pumps Enhance Production and Processing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164256, ’Novel Examples of the Use of Surface Jet Pumps To Enhance Production and Processing: Case Studies and Lessons Learned,’ by Syed M. Peeran, Najam Beg, and Sacha Sarshar, Caltec UK, prepared for the 2013 SPE Middle East Oil and Gas Show and Exhibition, Manama, Bahrain, 10-13 March. The paper has not been peer reviewed. Surface jet pumps (SJPs) are simple, low-cost, passive devices that use a high-pressure (HP) fluid as the motive force to boost the pressure of produced-gas and -liquid phases. In recent years, the oil and gas industry has become more aware of their applications and benefits. These systems enable the flowing wellhead pressure (FWHP) to be reduced in order to increase production while meeting downstream production-pressure requirements. SJP Operation and Applications In an SJP, the HP fluid passes through the nozzle, where part of the potential energy (pressure) is converted to kinetic energy (high velocity). As a result, the pressure of the HP fluid drops in front of the nozzle. It is at this point that the low-pressure (LP) flow is introduced. The mixture then passes through the mixing tube, where transfer of energy and momentum takes place between the HP and LP fluids. The mixture finally passes through the diffuser, where the velocity of fluids is gradually reduced and further recovery of pressure takes place. The pressure at the outlet of the jet pump will be at a value between that of the HP fluid and that of the LP fluid. Fig. 1 illustrates the general configuration of the SJP. In the case of gas production, both HP and LP fluids are primarily gas. The presence of liquids (condensate, oil, or water) in the LP flow can be tolerated as long as the volumetric flow rate of liquids is less than 1 to 2% of the volumetric flow rate of the LP gas at the operating pressure and temperature. Beyond these values, the effect on the achieved pressure difference (ΔP)—discharge pressure minus LP pressure value—could be significant, requiring the LP liquids to be separated upstream of the SJP and to be boosted separately. Alternatively, the LP liquids can be sent to a part of the process system that operates at a lower pressure, if such a source is available. The presence of liquids in the HP gas also has a similar limitation, beyond which the liquids need to be separated upstream of the SJP. The main reason in this case is that the performance and sizing of the nozzle are affected on the basis of whether the HP flow is liquid or gas phase. A further point is that if the HP flow is multiphase, the fluctuating flow regime associated with multiphase flow reduces the efficiency of the SJP significantly further, because the mixture is not usually homogeneous. The exceptions in these cases are transient conditions such as startup, when the system may be subjected to a high flow rate of liquids passing through the SJP. The SJP recovers quickly in such cases as soon as the liquids pass through. If no HP gas is available in gas-production applications, the HP source can be an HP liquid (oil or water). In this case, the solution is viable and economical mainly when the LP-gas-flow rate is small and is limited to a few MMscf/D. The reason for this limitation is the relatively high volumetric flow rate of liquids needed for each MMscf/D of the LP gas.

Matrix Acidizing Innovation Surpasses Competing Methods in Saudi Carbonate

Technology Update Matrix acidizing is a method of stimulating carbonate reservoirs for oil and gas production. Unlike acid fracturing, matrix acidizing creates conductive flow channels, also known as wormholes, which possess much higher conductivity than the reservoir rock. These conductive channels transport reservoir fluids from within the formation matrix directly into the wellbore overcoming both low permeability and near wellbore damage. In matrix acidizing of moderate to prolific carbonate reservoirs, efficient acid placement is a major challenge, as acid tends to flow preferentially toward intervals with the highest permeability. It can result in overstimulation of these areas, leaving the low-permeability intervals untreated. A significant percentage of matrix acidizing treatments do not meet expectations because of an improper job design and acid placement. In some cases, an increase in water production occurs after a stimulation job as a result of preferential stimulation of high-permeability sections associated with water. Case Study: Khuff Carbonate Khuff is a carbonate formation deposited on a shallow continental shelf in the Ghawar structure of eastern Saudi Arabia. It is divided into four intervals, A to D, with production mainly coming from the two gas-bearing layers: Khuff-B, a tight dolomite, and Khuff-C, a more prolific calcite. Since its initial appraisal in the late 1970s, the majority of Khuff’s development activities have focused on the Permian Khuff-C formation. Extensive heterogeneity in stress, reservoir quality, and reservoir fluids throughout the field, combined with the deep and hot nature of the reservoir, makes effective stimulation of all layers a challenging task. All Khuff gas-producing wells require acid stimulation either by acid fracturing or matrix acidizing to obtain high production rates and sufficient flowing wellhead pressure to be tied into production facilities. Until mid-2011, the majority of Khuff horizontal gas wells were drilled toward the maximum horizontal in-situ stress (σmax) to enhance wellbore stability and achieve the best penetration rates. However, when multistage fracture stimulation is desired and the well is drilled in the max direction, the fractures will grow longitudinally (parallel to the wellbore) and cause potential risk of overlapping with subsequent fractures. Therefore, initiation of the second and third fractures becomes a challenge because of possible pressure communication across the first induced fracture. To avoid fracture overlapping, a well slated for multistage fracturing should be drilled toward the minimum horizontal in-situ stress (emin), which allows transverse fracture growth (perpendicular to the wellbore). Drilling wells toward min often poses challenges, such as wellbore instability and differential sticking, but the improved long-term productivity justifies the strategy.

Handling Jurassic Field Sour Gas Creates Challenges Upstream and Downstream

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154452, ’Challenges in Sour-Gas Handling for Kuwait Jurassic Sour Gas,’ by Bader Nasser Al Qaoud, SPE, Kuwait Oil Company, prepared for the 2012 SPE Middle East Unconventional Gas Conference and Exhibition, Abu Dhabi, 23-25 January. The paper has not been peer reviewed. Kuwait Oil Company started free gas production from its Jurassic sour-gas field in May 2008 with the commissioning of Early Production Facility (EPF) 50. The field produces sour gas and light crude from a deep high-pressure/high-temperature naturally fractured carbonate reservoir with low permeability and low porosity. The well fluid is characterized by high hydrogen sulfide (H2S) (5%) and carbon dioxide (CO2) (5%) content. Handling such highly corrosive well fluid creates a wide range of challenges, from upstream at the wellhead to downstream at the processing facility. Upstream Challenges Upstream challenges for the Jurassic gas field have been related mostly to subsurface corrosion of tubing, unplanned well downtime because of hydrate formation during winter, and failure of automated chokes for some wells. Subsurface Tubing Corrosion. A moderate to severe corrosion rate has been indicated by corrosion logs in the production tubing because of the high H2S and CO2 content of the well fluid. Plans exist for existing carbon-steel tubing for four wells to be replaced by corrosion-resistant alloy material, and regular corrosion logs are being run for other suspect wells. Hydrate Formation in Flowlines. Hydrate formation has been observed in flowlines during winter for 11 wells when flowline temperature drops to 65°F. This has resulted in unplanned production loss and substantial well downtime. The best mitigation option implemented was the injection of kinetic hydrate inhibitor (KHI) at the wellhead at the onset of winter for the identified wells, and a good degree of success has been achieved. However, KHI is not very effective in controlling hydrates at temperatures below 4°C, and this is a problem that needs to be addressed as a priority. Flowline insulation at the point of restriction and heat tracing also have been implemented for four wells, with a fair amount of success. Challenges With Automated Chokes. Automated chokes were first installed in the field in April 2011. The purpose of automation was to improve control of remotely located wells, enhance safety, and ensure better control of field production. Sixteen Jurassic wells are currently on automated chokes of three different makes—M1, M2, and M3. Challenges With Make M1. The factory-set choke opening did not match actual choke opening. Choke adjustments had to be made with flowing wellhead pressure (FWHP) as a reference, and this leads to inaccurate settings. Scale formation also has been observed in-side the choke body, causing restricted flow and inaccurate FWHP readings and, therefore, poor monitoring of well performance.

Introducing a New Correlation for Multiphase Flow Through Surface Chokes With Newly Incorporated Parameters

Summary Flow-rate prediction of oil production wells is of prime importance to effectively confront high-water-cut and separator problems. (Semi-) empirical multiphase-flow correlations are proved quite useful for this purpose. This work presents new generalized multiphase flow choke correlation, derived on the basis of actual production data from horizontal and vertical wells from an oil field in Iran. The newly established correlation predicts liquid flow rates as a function of flowing wellhead pressure, gas/liquid ratio, surface wellhead choke size, and the newly incorporated parameters: basic sediment and water (BS&W) and temperature. To evaluate the influence of these two new parameters, a parameter-sensitivity analysis was performed and the results are shown. This proposed correlation exhibited an average error of roughly 2.89%, which is superior to those previous correlations in the literature that did not use these two newly incorporated parameters (BS&W and temperature). These new parameters can be added to the previous correlations when the water cut and temperature become important in the production history of the wells.

Positive effect of earthquake waves on well productivity: Case study: Iranian carbonate gas condensate reservoir

Artificially made seismic waves have been used for both tertiary recovery and well stimulation purposes. The idea behind using this method for enhancing recovery came from a number of real examples, in which a kick in oil production has been seen following an earthquake. Most published information has addressed the United States and earlier Soviet Union regions. This paper documents the results of observations regarding the effect of earthquake waves on well production from Khami carbonate gas condensate reservoir in the Marun field, in the northern Persian Gulf. The response of three wells in this reservoir (referred to as wells A, B, and C) to a magnitude M=5.7 earthquake at an approximate distance of 217 km away is discussed. After this earthquake, there was a sharp significant increase in production from well A. The flowing wellhead pressure of this well suddenly increased from 4263 to 5042 psig and went back to its normal condition after five months. The two other wells behaved differently and showed no change in production. Analyses showed the removal of near wellbore formation damage caused by a condensate dropout in well A using natural seismic waves.

New multiphase choke correlations for a high flow rate Iranian oil field

Abstract. The multiphase flow through wellhead restrictions of an offshore oil field in Iran is investigated and two sets of new correlations are presented for high flow rate and water cut conditions. The both correlations are developed by using 748 actual data points, corresponding to critical flow conditions of gas-liquid mixtures through wellhead chokes. The first set of correlations is a modified Gilbert equation and predicts liquid flow rates as a function of flowing wellhead pressure, gas-liquid ratio and surface wellhead choke size. To minimize error in such condition, in the second correlation, free water, sediment and emulsion (BS & W) is also considered as an effective parameter. The predicted oil flow rates by the new sets of correlations are in the excellent agreement with the measured ones. These results are found to be statistically superior to those predicted by other relevant published correlations. The both proposed correlations exhibit more accuracy (only 2.95% and 2.0% average error, respectively) than the existent correlations. These results should encourage the production engineer which works at such condition to utilize the proposed correlations for future practical answers when a lack of available information, time, and calculation capabilities arises.

Intelligent Design and Modelling of Natural Gas Storage Facilities

Underground gas storage reservoirs provide an efficient and economical way to match the constant supply of gas from long-distance pipelines to the variable, weather-driven demand of the natural gas market. The most important design specifications for underground natural gas storage facilities in terms of startup and operation costs are its capacity, maximum reservoir pressure, number of wells required for drainage, flowing wellhead pressure, and the ratio between working gas and cushion gas. The relationships between these variables are quite complex, and a need exists for a reliable predictive tool. Despite these complexities, the optimal combination of these design parameters can be reached using artificial neural network (ANN) technology. In this study, ANN technology creates an intelligent system capable of learning the complex relationships between input parameters and output responses, which can quantify the importance of each relationship and design variables critical to the determination of optimal design.

Enhanced compartmentalization of a complex reservoir with sub-seismic faults from geological inversion

Sealing faults are fundamental for delimitation of compartments in a reservoir and they are usually identified by geological interpretation of 3D seismic data which are limited to the resolution of seismic sections. Dynamic production data may suggest in some cases the existence of smaller faults or vertical discontinuities which may not be detected from seismic. It is reasonable to assume that, with increasing resolution of 3D seismic, large faults could be accurately identified while faults with strike slip or small throw may remain invisible to seismic. This paper proposes a geological inversion approach for modeling sub-seismic vertical discontinuities or faults using dynamic data. The methodology is based on a prior self-similar generation of faults which are geometrically downscaled from larger faults interpreted from seismic. Then, the approach follows an iterative inverse Gauss–Newton modeling technique to update fault size and location parameters based on the reservoir pressure response. The convergence criteria include comparing both the observed and model calculated shut-in bottom-hole pressure (SBHP) and flowing well head pressure (FWHP) until the squared differences between the observed and model calculated pressures diminish to a minimum. If the convergence criteria were not met, the fault pattern is modified and the geocellular grid is cut with updated faults to generate a new version of the faulted simulation model for the next iteration. As an alternative, commercial assisted history match (AHM) software can be utilized to expressively adjust fault locations in the simulation model to match the production history; however, such perturbations are not done at the geological level as in the proposed approach. Thus, the approach in this paper has the advantage of preserving the spatial and geological integrity of the geocellular model. In addition, the spatial consistency between the geological and simulation models is always guaranteed in the proposed approach.

A New Effective Stimulation Treatment for Long Horizontal Wells Drilled in Carbonate Reservoirs

Summary Effective matrix acidizing of horizontal and multilateral wells can be a highly challenging task. Unlike vertical wells, horizontal wells can extend several thousand feet into the formation. Reservoir heterogeneity and the length of the horizontal leg can make acid placement and diversion very difficult. In addition, the low drawdown encountered in horizontal wells results in longer times to lift the spent acid from the well, especially in tight formations. To achieve better acid diversion in horizontal wells drilled in carbonate reservoirs, a viscoelastic-surfactant-based system was used. The components of this new system are HCl and a viscoelastic surfactant. The acid dissolves calcite and dolomite minerals and produces calcium and magnesium chlorides. The increase in pH forces the surfactant molecules to form rod-shaped micelles. The produced chloride salts further stabilize these structures, especially at high temperatures. The rod-shaped micelles will significantly increase the viscosity of the acid, diverting the acid into tight, unstimulated, or severely damaged zones. More than 100 wells with openhole (OH) completions were successfully stimulated in two offshore oil fields in Saudi Arabia by use of the new acid system. With a water zone 30 ft away from these OH sections in one of the fields, growth of any dominant wormhole into these sections could increase water production. The wells that used the new treating fluid produced an average of 1,600 BOPD more than conventionally treated wells, with no indication of water production. Field results [pre- and post-oil and -water production rates and flowing wellhead pressure (FWHP)] demonstrate the effectiveness of the new acid system to matrix acidize long horizontal wells with OH completions. The simplicity of the system makes it the fluid of choice, especially in offshore and sour environments. The absence of metallic crosslinkers in this system eliminates problems associated with sulfide precipitation in sour wells.

Understanding Gas-Well Load-Up Behavior

Summary This paper describes the hydraulics of wellbore load-up for gas wells. Atheoretical model of transient load-up hydraulics is presented and comparedwith field test data. Application of this technology allows predictivetechniques to be used in predictive techniques to be used in analyzing gas-wellload-up. It also establishes an understanding of loadup behavior, which isvaluable in analyses of production problems and evaluations of productionalternatives for low-pressure gas wells. Introduction Part 1 of this series outlined data that Part 1 of this series outlined datathat validated the theory for predicting the critical rate, qc, forlow-pressure gas wells. This second part outlines and validates the theory forpredicting the behavior of a low-pressure gas well after qc is reached, whenthe well is in an unsteady-state load-up condition. Doing so will offer abetter definition of gaswell load-up behavior and a better understanding of howto cope with the problem. To understand the transient load-up condition, it is helpful to construct apicture of a gas well in load-up (Fig. 1). Fig. 1a represents a well flowingabove its critical rate; i.e., qg >qc. In this state, at t=O, all fluidproduced with the gas is carried out of the produced with the gas is carriedout of the wellbore conduit and the wellbore exhibits a relatively predictable, steady-state behavior. The drive energy available that causes gas to flow from this well is boundedby the average reservoir pressure in the well's drainage area, PR and thesystem pressure, Ps' The flowing sandface pressure, Psf' is Ps' The flowingsandface pressure, Psf' is dictated by the reservoir performance. The flowingwellhead pressure, psf, is controlled by the performance of any surfaceequipment or pipeline. At the onset of load-up where qg less than qc and t=1, liquid is no longercarried out of the wellbore; instead, it is held up in the wellbore in the formof an aerated column (Fig. 1b). The same boundary conditions exist for thedrive energy; however, psf and p, qr converge toward their pressure p, qrconverge toward their pressure boundaries as the produced fluid accumulates andincreases the hydrostatic pressure of the flowing gas column. The sandfacepressure, psf gradually increases until it is equal to psf gradually increasesuntil it is equal to the average reservoir pressure, PR This increase in psfwith time causes a comparable decline in gas flow rate and During this load-up period, the pressure loss in the well flowline (Pwf-ps), the gas column in the wellbore (Pli-Pwf) and the reservoir drawdown (Pe-Psf)all decrease because these pressure losses are primarily frictional anddecrease with decreasing flow rates. However, the pressure caused by thebuilding of a hydrostatic liquid column in the wellbore (Psf-Pli) increases. This hydrostatic column continues to build until such time as the hydrostaticconditions of the wellbore, combined with pwf balance the reservoir drivingforces and cause the well to die (Fig. 1c). Now, at t=2, the well is completelyloaded and qg=0. Once this occurs, PR continues to increase until it either equalizes withthe reservoir pressure at the well's drainage radius boundary, Pe at t=3 orovercomes the load-up-induced hydrostatic head and begins to unload thewell. The well's ability to unload itself depends on such variables as reservoirtransient flow performance, remaining amount of load performance, remainingamount of load fluid, changes in the system pressure boundary and wellboreconfiguration and depth. When a well can no longer complete the unloading cyclenaturally, it has reached its "blowdown limit which is covered in Part 3 ofthis series. Theory This description of gas-well load-up can be modeled predictively withconventional quantitative analysis techniques. First. because gas-well load-upis driven by the time history of the liquid column height, it is necessary todefine a liquid control volume, as shown in Fig. 2. The primary differentialequation to be solved for the liquid balance is With the definition of the liquid holdup fraction,3 YL, Then, To solve Eq. 3, an expression for the rate of liquid in and liquid out, QLinand QLout must be determined. JPT P. 334

The United Nations' approach to geothermal resource assessment

Although the emphasis of United Nations' assisted geothermal projects has been on demonstrating the feasibility of producing geothermal fluids, the potential capacity of individual fields has been estimated by both the energy in place and decline curve methods. The energy in place method has been applied to three geothermal fields resulting in total resource estimates ranging from 380 to 16,800 MW-yr. The results of these studies must be considered highly tentative, however, due to inadequate reservoir data and a poor knowledge of producing mechanisms. The decline curve method has not given quantitative results concerning ultimate field potential because of the relatively short duration of well tests (several weeks to a maximum of 11 months). In all cases, however, the decline of flowing wellhead pressure, field pressure, and flow rate has continued to decrease with time. A new method for making regional assessment of geothermal potential is described, which is based, in part, on an assessment of the probable range of the power potential of geothermal fields as inferred from a frequency distribution analysis of fields already under development throughout the world. Depending on the reservoir containing dry steam or water, and its location in a region of groundwater recharge or discharge, average power potentials can be expected to range from 36 to 3360 MW.

Calculating the Steam-Stimulated Performance of Gas-Lifted and Flowing Heavy-Oil Wells

Calculating the Steam-Stimulated Performance of Gas-Lifted and Performance of Gas-Lifted and Flowing Heavy-Oil Wells Here is a method for combining reservoir and wellbore pressure-drop calculations to predict the performance of steam-stimulated wells producing by natural flow or by gas lift. The extent to which such process variables as treatment size, lift-gas rate, wellhead pressure, and prestimulation rate affect performance can be calculated with this method. Introduction When fluids are produced from the reservoir in which they are found and transported to separation or treating facilities on the surface, three basic types of multiphase fluid flow are encountered: Flow to the wellbore through the porousmedium, Vertical flow in the wellbore from thesandface to the wellhead, and Horizontal flow through flowlines from thewellhead to the surface facilities. The first two types of flow are coupled by the flowing bottom-hole pressure at the sand-face; the latter two types are coupled by the flowing wellhead pressure. A complete description of such a system requires simultaneous solution of the three flow problems. A method for simultaneously solving the reservoir and wellbore flow problems has been developed for use in calculating the steam-stimulated performance of a well that is either flowing or being produced by continuous gas lift. For simplification, it has been assumed that the wellhead pressure can be specified. This implies that the flowline is short or is adequately sized to have only a minor pressure drop. This is not always the case in practice, and it may sometimes be desirable to incorporate a flowline pressure drop calculation. pressure drop calculation. It is important that the wellbore and reservoir flow problems be considered in combination for the problems be considered in combination for the following reason. For a given wellhead pressure, the flowing bottom-hole pressure - and hence production rate - is controlled by the pressure drop that occurs in the wellbore. This pressure drop is a function of the oil, water, and gas flow rates and fluid properties, some of which are strongly temperature properties, some of which are strongly temperature dependent. The problem is compounded in steam-stimulated wells because both the flow rates and the temperature change significantly during the production cycle. For a well producing viscous oil, the production cycle. For a well producing viscous oil, the change in temperature is particularly important because of its effect on oil viscosity. A temperature change of only 60 deg. F in the tubing string can often result in a difference of several hundred psi in the flowing bottom-hole pressure, with a consequent effect on production rate. Under some conditions, variations in pressure drops in surface flowlines can also be significant and must be considered because of their influence on wellhead pressure. The paper describes how two previously published techniques were combined to solve the stated problem, illustrates the combined method by example problem, illustrates the combined method by example calculation, and establishes the validity of the method by comparing calculated and field results. Also, the method is used to calculate the extent to which several important process variables, such as treatment size, lift-gas rate, wellhead pressure, and prestimulated production rate, affect stimulated performance. prestimulated production rate, affect stimulated performance. JPT P. 1207