Wellhead Back Pressure Research Articles

A Case Study in Oil-Gas Transportation through Subsea Pipeline in Liaohe Tanhai Oilfield

The crude oil in Kuidong region of Liaohe Tanhai Oilfield is characterized by high oil viscosity, high density, high content of colloid asphalt, low content of wax and low freezing point. In the shallow region, the large current, high content of silt, long-distance subsea buried pipeline and drift ice in winter have brought great challenge to offshore construction and oil-gas transportation. In this paper, the investigations of offshore construction project and platform process are shown. Based on the well production rate, gas-oil ratio, water cut, wellhead back pressure and outlet temperature, the range of daily transportation volume was acquired, as well as the maximum inlet pressure and pressure difference of the pump. The paper also selected technically and economically feasible pumps, then designed the public projects, corresponding electric power and self-control facilities. The selected skidded twin screw multiphase pump system can smoothly transport produced liquid to the terminal systems onshore without any effect on the daily output.

Prediction of dynamic wellbore pressure in gasified fluid drilling

The basis of designing gasified drilling is to understand the behavior of gas/liquid two-phase flow in the wellbore. The equations of mass and momentum conservation and equation of fluid flow in porous media were used to establish a dynamic model to predict wellbore pressure according to the study results of Ansari and Beggs-Brill on gas-liquid two-phase flow. The dynamic model was solved by the finite difference approach combined with the mechanistic steady state model. The mechanistic dynamic model was numerically implemented into a FORTRAN 90 computer program and could simulate the coupled flow of fluid in wellbore and reservoir. The dynamic model revealed the effects of wellhead back pressure and injection rate of gas/liquid on bottomhole pressure. The model was validated against full-scale experimental data, and its 5.0% of average relative error could satisfy the accuracy requirements in engineering design.

Subsea Oil/Water Separation: Main Drives and Challenges

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97375, "Application of Subsea Oil/Water Separation: Main Drives and Challenges," by M.W. de Figueiredo, Petrobras, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June. Petrobras is developing a subsea system for oil/water separation to minimize the effect that high water-production rates cause to the topside facilities when waterflooding an oil field. Most of the produced water can be separated at the seafloor and reinjected into the reservoir or into a water-bearing formation. Introduction During the exploitation-design phase of an oil field, activities focus on oil-production optimization. The oil-recovery mechanism is defined to maximize the recovery factor according to the reservoir and fluid characteristics. In most of the oil fields in Campos basin, waterflooding is used from the beginning of production. After water breakthrough occurs, the handling of produced water, which is a mixture of injected seawater and reservoir water, is of secondary importance during the design phase. Its priority increases only after water production increases. Conventionally, this water is separated from the oil and disposed of into the sea. This procedure takes place onboard the floating production units (FPUs) by use of very-large-volume vessels on a deck where space is critical, especially with the increasing plant capacity of recent units. The use of a subsea system to separate most of the produced water at the seabed and send it somewhere other than the FPU plant is an attractive option. Such a system would allow the production plant to continue handling only a residual amount of water, eliminating new construction onboard to increase water-handling capacity. This system could enable adding extra oil-processing capability and, in many cases, increase oil production because of the lower wellhead backpressure that results from reduced water-lifting energy requirements. Subsea separation presents challenging issues such as compactness and reliability. The full-length paper details this development, including the most promising scenario and the main benefits and challenges related to this scenario.

Oilwell Deliverability Monitoring: A Case History

SummaryThis paper presents a case history study that demonstrates a method to monitor wellhead-deliverability performance for flowing oil wells in a manner similar to gas wells. Separator test data measured for production allocation are used along with the material-balance relationship and multiphase-flow analysis to develop a wellhead backpressure curve for flowing oil wells. An equivalent wellhead static pressure for flowing oil wells is described and shown to be a function of reservoir depletion and multiphase-flow rate. Determination of the equivalent wellhead static pressure extends our understanding of wellhead backpressure analysis for both flowing oil and gas wells.A case history example demonstrating the application of the methods described in the paper is developed with the separator test data from Point Arguello field wells. The resulting wellhead backpressure curves clearly defined individual well deliverability and proved to be valuable diagnostic tools to monitor well performance and to quantify production potential. We show that the procedures developed in this paper are directly equivalent to procedures applied to conventional gaswell wellhead backpressure analysis commonly used in the industry to monitor gaswell performance. By monitoring flowing oilwell performance with the methods described in this paper, operators can address the challenge of maintaining well productivity and field production plateau.

Developments in geothermal energy in Mexico—part seven: Thermodynamic analysis of the operation of geoethermal electrical power generation facilities

The operating histories and performance of a large (180 MW e) central condensing plant and five small (5 MW e) wellhead backpressure power plants are presented. The thermodynamic performance of the central plant is compared with an estimated possible performance based upon the work of Michaelides [2]. Both types of plant have been shown to be reliable despite some problems due to the contaminants which are associated with geothermal steam.

Analyzing the Performance of Gas Wells

Summary Methods for analyzing gas well performance are presented. Inflow, outflow, and tubing performance presented. Inflow, outflow, and tubing performance curves are defined, and examples of each are given. These curves are the primary tools used to visualize and graphically predict the effects of declining reservoir pressure, increasing water production, changing tubing pressure, increasing water production, changing tubing sizes, or installing gas compressors. A graphical method for determining an accurate reservoir abandonment pressure is also presented. The concept of "flowpoint" pressure is also presented. The concept of "flowpoint" and it importance in understanding gas well behavior is explained. Introduction Understanding the flow characteristics of gas wells has become increasingly important to those in the petroleum industry as the economic importance of gas has increased. During 1970–80 the average annual wellhead price of all natural gas in the U.S. rose from $0.171 to price of all natural gas in the U.S. rose from $0.171 to $1.496/Mcf. Gas purchasers are currently paying in the $5.00/Mcf range and have paid more than $9.00/Mcf in some areas. It is now possible to understand and to predict the flowing characteristics of any gas well with a good degree of accuracy from a minimum of field test data. The entire range of a gas well's flowing performance may be determined from a single well test, a current reservoir pressure, and published mathematical correlations. Inflow Performance Curves One of the most widely used methods for mathematically describing the downhole performance of a gas well is the empirically derived relationship (1) where q = rate of flow, Mcf/D, C1 = a numerical coefficient, characteristic of theparticular well, p = shut-in reservoir pressure, psia, p = shut-in reservoir pressure, psia, pwf = flowing bottomhole pressure (BHP), psia, pwf = flowing bottomhole pressure (BHP), psia, and n = a numerical exponent, characteristic of theparticular well. This equation represents a straight line drawn through well-test data points plotted on log-log graph paper as shown by Curve A in Fig. 1. The numerical constant, C1, controls the placement of the performance curve to the tight or left along the horizontal axis of the graph, and the exponent, n, represents the reciprocal of the curve's slope. In Fig. 1, n is equal to the cotangent of the angle theta. This angle is usually about 45 deg., and n is about 1.0. Under normal conditions, a performance curve may be approximated by plotting a single well-test point and drawing a 45 deg. plotting a single well-test point and drawing a 45 deg. performance curve line through it. performance curve line through it. The procedure for collecting these well-test data is commonly called a "backpressure test" or "four-point test. "The primary purpose of this type test and graphic plot is to project a well's performance to what it would plot is to project a well's performance to what it would be with a flowing BHP, pwf, of zero. The gas rate established by this projection is obviously the maximum possible and is appropriately called the "absolute open possible and is appropriately called the "absolute open flow" (AOF) of the well. The calculated AOF of a well is a fundamental measure of its ability to produce. It is a good measure to use when comparing gas wells in different areas because the many and varying effects of well depth, tubing size, wellhead backpressure, etc., are eliminated by working with downhole other than surface measurements of rates and pressures. JPT P. 1378