Vertical modeling, a tool based on theoretical background, simulates the pressure response in a vertical well within a rectangular shaped reservoir with homogeneous characteristics. The objective of this study is to perform pressure transient analysis to estimate reservoir parameters of kailashtilla gas field based on pressure and production data. A vertical model is matched to pressure history as an inverse process to extract the reservoir parameters and compared with the estimated and Al Mansoory Wireline Services resultant parameters. Deliverability test is performed to measure production capabilities.
With the advent of downhole permanent gauge reliable gathering of flowing bottomhole pressure is on the rise. This essential bottomhole reservoir data is subtracted from the reservoir average pressure to calculate pressure drawdown. The resulting drawdown is commonly used to estimate well productivity index. In this paper we demonstrate how drawdown can be used to generate a decline curve which is extrapolated to estimate future recovery potential.
We show in detail how this method is used to estimate future production performance by linearization of drawdown-time curve and drawdown-cumulative curve and thereafter extrapolate the resulting straight-lines into the future.
The commonly applied method to estimate future recovery potential of a producing well is to plot its production rate against cumulative production or against time and thereafter extend the semilog straight-line to some economic limit. The point of intersection of the economic limit and the extrapolated straight line demonstrate the well ultimate recovery1. This method assumed that the past reservoir behavior is carried into the future such that the well future performance is controlled by
thesame past reservoir fluid dynamics. This assumption in which the extrapolated decline-curve is developed is usually amended when there are changes to the well production method1. There are three basic types of rate-time decline equations which are exponential, hyperbolic and harmonic equations1. The theoretical basis for these decline curve equations assumed that the well is in boundary-dominated flow such that the flowing bottomhole pressure, productivity index, skin factor, and drainage radius are constant.
Until now production decline-curve analysis has been carried out utilizing well production rates. The well rate is used because it is one of the most easily available data of a producing well1. As common as this data is it is seldomly measured on daily or monthly basis but allocated based on some measured well test rates. This allocated well production rates are utilized for production decline-curve analysis.
Nowadays, another readily available well data is bottomhole pressures. Not only is bottomhole pressures commonly available but it is measured at time frequency as high as per seconds thereby improving the accuracy of this readily obtainable well data. This regular well data measurement is made possible with the advent of permanent downhole pressure gauges that is installed in producing wells to measure high frequency bottomhole pressure data.
This paper demonstrates how measured well bottomhole pressure is utilized to develop a pressure-drawdown-cumulative curve and pressure-drawdown-time curve. The pressure-drawdown-cumulative curve is obtained by subtracting bottomhole pressure from average reservoir pressure and thereafter makes a log-log plot of drawdown pressure against cumulative production. The resulting straight-line is extrapolated into the future to yield ultimate recovery. The pressure-drawdown-time curve is obtained by making a log-log plot of drawdown pressure against cumulative uptime. The log-log straight-line is projected into the future to yield pressure drawdown economic-limit.
Low permeability, shale barriers and low thickness are the main issues making significant portion of the immense heavy oil and bitumen resource uneconomical to produce. Two main troublesome cases were investigated in this study to address by applying appropriate solutions in SAGD process; firstly reservoirs with shale barriers and low permeability and secondly thin reservoirs.
In cases of low vertical permeability due to shale inclusion in the reservoirs, the effect of induced vertical fracture resulted in faster upward steam chamber expansion and increased oil recovery rate. Sensitivity analysis showed higher well spacing is beneficial to the process while applying the induced vertical fracture. In thin reservoirs, steam chamber reaches overburden faster and increases cumulative steam-oil ratio (cSOR), hence making recovery processes uneconomical. Appropriate placement of Induced Horizontal-Fractures (IHF) and off-set vertical wells with the later being in halfway of two adjacent horizontal well pairs in SAGD and acting as a steam injector was applied. The results showed such applications reduce cSOR.
Found from the sensitivity analysis, Induced Horizontal-Fractures positioned in the injector and the producer place improves oil recovery in thin reservoirs. When applying the fracture just in producer location, the oil recovery result is superior to the former case. In fact, IHF provide a path facilitating the oil drainage to producer that leads to faster oil transportation. The Off-set vertical well in the thin reservoir sweeps a part of the reservoir located beyond the chamber edges of two adjacent well pairs, hence reducing recovery time and cSOR. Based on sensitivity analysis, the most promising result of the process is achieved when initiating steam injection in the vertical injector from the beginning of the process.
Keywords: SAGD, Uneconomical tarsands, Thin reservoirs, Shale content
Revitalizing aging fields can be complicated when viewed through an outlook of economic viability versus the associated operational and design risks. However, workover campaigns may be deemed more economically efficient and lower risk with the continuous advancements in technology, especially applicable to smart well designs. Workover projects are becoming ever more viable, with production being optimized through the application of advanced well construction products such as Solid Expandables along with existing brownfield infrastructure.
The operator of the Hassi Messaoud field, one of the largest and oldest onshore oil producing fields in Algeria, embarked on a large scale workover campaign to revitalize this field and optimize oil production from wells which have been drilled over 40 years ago. The typical workover program targeted extending the open-hole below the 7-in. casing across the Cambrian reservoir and completing the wells with a 4-1/2-in liner. Challenges with various formations encountered and the depleted reservoir resulted in the viability of only a slim hole configuration restricting production.
Maximizing the wellbore diameter across the reservoir while isolating higher pressured shale's directly above and balancing the economic return on investment required the inclusion of multiple technologies to achieve the well and production objectives, all using the existing well infrastructure.
A total of 7 wells have been worked over to date since early 2010 which avoided slim-bore configurations through the inclusion of 939m of 5-1/2?? expandable tubular maximizing reservoir diameter and serving as a permanent mechanical barrier. The campaign also incorporated underbalanced drilling operations as a tool for mitigating subsequent pressured formations and testing production as required. The actual campaign had a reduction in operational time of 40% while
significantly increasing and optimizing production rates.
The Hassi Messaoud field is located in the Ouargla Province of Algeria and was originally discovered in 1956. Reserves are expected to be approximately 6.4 billion barrels and the current production is around 350,000 barrels per day (56,000 m3/d) with the hydrocarbons being produced from a Cambrian sandstone reservoir which is situated in a large dome. Production depths are achieved at approximately 11,000 ft (3,300 m) with the oil column approximately 900ft (270 m) in length. A total of 178 wells had been drilled to the end of 1967, 39 of which were dry or produced water, and 30 of which were producing at a rate greater than 6,000 bbl/day1.
An operator within the Hassi Messaoud field embarked on a workover campaign to increase production rates in wells which had previously been drilled up to 40 years ago, although they posed many constraints and challengers. Gradual depletion of the reservoir had resulted in an increased differential pressure between subsequent exposed intermediate formations, resulting in wellbore instability and production issues that have resulted in the operator shutting in the wells.
In hydrocarbon reservoirs, fluid types can often vary from dry gas to volatile oil in the same column. Because of varying and unknown invasion patterns and inexact clay volume estimations, fluid types differentiation based on conventional logs is not always conclusive. A case study is presented utilizing advanced nuclear magnetic resonance (NMR) techniques in conjunction with the latest downhole fluid analysis (DFA) measurements from wireline formation testers to accurately assess the hydrocarbon type variations.
The saturation profiling data from an NMR diffusion-based tool provides fluid typing information in a continuous depth log. This approach can be limited by invasion. On the other hand, formation testers allow taking in-situ measurements of the virgin fluids beyond the invaded zone, but only at discrete depths. Hence, the two measurements ideally complement each other.
In this case study, NMR saturation profiling was acquired over a series of channelized reservoirs. There is a transition from a water zone into an oil zone, and then into a rich gas reservoir, indicated by both the DFA and the NMR measurements. Above the rich gas is a dry gas interval that is conclusively in a separate compartment. Diffusion-based NMR identifies the fluid type in a series of thin reservoirs above this main section, in which no samples were taken. NMR and DFA both detect compositional gradients, invisible to conventional logs.
The work presented in this paper demonstrates how the integration of measurements from various tools can lead to a better understanding of fluid types and distribution.
This work investigates the flow structure development due to injecting water into the annulus of heavy oil pipe flow. Numerical simulation of the axisymmetric core annular turbulent flow is carried out using the standard k-? model. The flow field and flow characteristics are investigated using FLUENT 6.3.26. The core annular flow of heavy oils-water in 15.24 cm diameter pipe, with three core diameters is considered. The influence of flow parameters upon the development of axial and radial velocity, turbulent kinetic energy, turbulent intensity, and strain rate profiles are investigated.
Results show that flow development depends on the core to outer diameters ratio, oil viscosity, flow velocity, and water loading ratio. As oil's viscosity increases, flow structure develops faster towards fully developed one. Fully developed velocity profiles show uniform distribution in oil's core, while all velocity changes occur in water flowing in pipe annulus. The flow in the core region seems to be as rigid body carried by annular water flow. It has been demonstrated that major changes in flow structure occur at the oil-water interface.
The progressive increase of oil demand coupled with the depletion of light crude oils has led to rapid development of the large world resources of heavy oils and bitumen. Conserved estimates show that heavy oil reserves are more than six trillion barrels throughout the world. The main problem of heavy oils production is the difficulty of transportation, due to the immense power requirement. Water lubrication of heavy oils and bitumen is an effective method for oil transportation in pipelines. Water is injected into the wall to encapsulate oil flows in the core region by annular water film along the pipe wall. This reduces drastically the pumping power and its cost of transportation of bitumen and heavy oil. Such common flow pattern of two-phase pipe flow of immiscible liquids is well-known as core annular flow "CAF??. Strazza et al (2011) stated that the pressure drop of oil-water core-annular flow is comparable to that of water flowing alone in pipeline even for extra heavy oils. Reviews on core-annular oil-water flow are found in Joseph et al. (1997), Xu (2007) and Ghosh et al. (2009). They surveyed studies on different aspects of the phenomenon covering models for levitation, determination of pressure drop, classification of flow types, and empirical correlations.
A new application for downhole data acquisition provides real-time wellbore intervention optimization via measurement-while-drilling (MWD)-based technologies to enhance pipe-conveyed wellbore intervention operations. This paper discusses the incremental challenges of conventional fishing methods that are addressed by using downhole data acquisition technology for ‘smart intervention' service in the following:
Retrieving deepset plugs
Pulling gravel-pack packers
A smart intervention module is one solution that is run in the workover string as close to the wellbore intervention bottomhole assembly as possible. It provides its own power supply, telemetry system, and sensors, and data is sent from the module via mud pulse telemetry to the surface, where it is displayed clearly on a rig floor monitor.
Surface rig-up requires a pressure transducer on the stand pipe or pumps, cables from the transducer to a junction box and the processor, which is connected to two real-time laptops. The smart intervention engineers provide 24-hr coverage, and both the smart intervention module and the surface equipment are included in the services provided.
The smart intervention system gathers downhole measurements like weight on tool, torque, revolutions per minute, bending moment, vibrations, pressure, and temperature to provide a clearer picture of what is occurring at and around the wellbore intervention tools. The data is then transmitted to surface where accurate, real-time decisions and adjustments can be made to optimize downhole intervention operations.
The Smart Intervention service uses traditional well-intervention tools and equipment in customary applications such as fishing and casing exits with one very major difference - the addition of Smart measurement technology. The tool is placed in any suitable intervention bottomhole assembly and contains a sensor aaray that measures all bottomhole physical conditions, such as weight -on tool, tension-on tool, torque, pressure, and rpm. The tool performs all data processing down hole and sends job applicable data to surface through a measurement-while-drilling (MWD) Pulser valve. A surface system detecs the pulses and processes the entrained data into easily read visual information on a drill floor display in real time.
A new method is presented to calculate the total inflow and associated productivity index (PI) under two-phase conditions by a sum of contributions from matrix and N multiple fractures using semi-analytical methods. Maximizing the net Present present value (NPV), the new inflow performance relationship (IPR) models can determine the optimal fracture stage number. Furthermore, the deliverable PI is used as an input to a network model to calculate the operating rate, taking into account the network constraints such as the node pressure, allowed flowrate, or choke in place. Through this analysis, one may determine that the horizontal well of interest may not flow at the maximum PI?it suggests that the network constraints dissipate the contribution from m stage(s) fractures. The number of fracture stages is then reset to (N-m), the IPR model is rerun, and an updated PI is imported into the network model. This process is iterated until the final optimization is achieved.
This method can quickly optimize the number of fracture stages for horizontal wells under two-phase solution-gas conditions, assisting operating companies in planning field development.
Semoga Field is an oil field in Rimau Block, which is located in South Sumatra, Indonesia. There is also a nearby oil field, Kaji Field, in this block. These fields experienced reservoir souring and suffered a history of calcium carbonate scale cases before a proper scale inhibition program was implemented. At the end of January 2011, there was a separation system problem at FWKO #2 Semoga Station. FWKO outlet lines were dismantled for inspection purposes, and it was found that the oil outlet line at the downstream of LCV was clogged by deposits, leaving only 0.5?? of ID.
XRD and XRF analysis confirms that the deposit is calcium carbonate scale, even though routine scale coupon monitoring shows very low scale growth. There is H2S scavenger brand X injection at the downstream of LCV on FWKO#2 with a concentration of 11,050 ppm. The scale inhibitor dosage in the water line on Semoga Station was only 9 - 10 ppm. Laboratory simulation shows that H2S scavenger brand X injection reduced the scale inhibition percentage from 97.2% to 35.3%, with 9 ppm scale inhibitor. Meanwhile, no deposits were found in the oil outlet line at the downstream of LCV at Kaji Station, which has the same H2S scavenger injection point and dosage. Scale inhibitor dosage in the water line on Kaji Station was 17.5 - 22 ppm. Laboratory simulation shows that 20 ppm scale inhibitor resulted in a scale inhibition percentage of 58%. Laboratory analysis shows that the scale inhibition percentage increases linearly as the scale inhibitor increases under H2S scavenger brand X influence.
However, another laboratory test conducted using H2S scavenger brand Y shows that the scale inhibition percentage will decrease with the increase of scale inhibitor concentration, until it reaches the lowest value before increasing again with the increase of scale inhibitor concentration. Thus, the scale inhibitor performance in H2S scavenger brand Y influence behaves parabolically.
It is concluded that H2S scavenger injection increases system pH, resulting in the increased of scaling tendency. However, adding scale inhibitor concentration is not always the answer to overcoming scale growth resulting from this effect. It is important to understand scale inhibitor performance behavior on certain H2S scavenger brands before taking preventive measures. Scale inhibitor performance might have a linear correlation between increasing concentration and scale inhibition percentage, as shown by the behavior with H2S scavenger brand X, but it might also have parabolic correlation, as shown by the behavior with H2S scavenger brand Y or even other correlation types. A proper understanding of scale inhibitor behavior can prevent a production loss caused by the deposition of 8,190 barrels of oil.
Semoga Field is an oil field in Rimau Block, which is located in South Sumatra, Indonesia. There is also a nearby oil field in this block, i.e. Kaji Field. All the fluid produced from these fields is gathered into three gathering stations, i.e. Kaji Station, Kaji Satellite and Semoga Stations. The fields had a history of calcium carbonate (CaCO3) scale before proper scale inhibition using scale inhibitor injection was implemented. Meanwhile, since the end of 2009, these fields have experienced reservoir souring, where H2S is being generated from the reservoir and entering the system. To reduce the H2S concentration in the facilities, H2S scavenger is injected into the system.
In its endeavor to provide a sustainable flow of hydrocarbon energy, the Petroleum industry has been recognized by the general public as an industry that has negatively impacted the environment as a result of using either harmful materials or risky practices. This leads the industry to continuously invest in R&D to develop environmentally friendly technologies and products. For any new technology or product, the current R&D trend is toward the development of sustainable practices and expertise.
Drilling fluids are necessary for drilling oil and gas wells. Unfortunately drilling fluids have become increasingly more complex in order to satisfy the various operational demands and challenges. The materials used in the process to improve the quality and functions of the drilling fluids, contaminates the subsurface and underground systems, landfills, and surrounding environment.
Due to the increasing environmental awareness and pressure from environmental agencies throughout the world, it is very important to look back to the drilling fluid technology to reassess its progress while it tries to make forward steps to improve the petroleum industry's position as an environment friendly industry. This article outlines the state-of-the-art of drilling fluids. The major types of drilling fluids, their strengths, limitations, and remedies to limitations are discussed. It also presents the current trend and the future challenges of this technology. In addition, future research guidelines are presented focusing on the development of environmentally friendly drilling fluids with zero impact on the environment. The paper concludes that future trend leads toward the development of sustainable
Generally, drilling fluid may be defined as all of the compositions used to assist the generation and removal of cuttings from a borehole in the ground. Drilling fluid is more or less the single most important part of any earth excavation exercise, especially when drilling for oil and gas. The drilling fluid can be compared with the blood of the human body, so also drilling fluid to drilling (Table 1).
Principal components of drilling fluids are: water, oil/gas, and chemical additives. These components form the basis of the classification of drilling fluids. Mud, which are suspension of solids in either water or oil, and a mixture of other substances called additives (Table 2) make a complete drilling fluid.