A well plan is essentially a decision-making roadmap for choosing equipment required for drilling the required wellbore. The operator's ability to properly assess offset drilling data and key lithology factors to match available BHA tools and procedures plays a large role in determining project success. Accordingly, the software support systems utilized to interpret and extrapolate data have a direct impact on the ability of drilling engineers to optimize operations.
Historically, most well plans were assembled using data from offset wells and prior experience. However in most cases, a rudimentary analysis could not produce a comprehensive picture of the complex, interdisciplinary downhole dynamics that affect drilling performance, especially in the case of limited or missing offset data. Even when reliable data was available, a one-dimensional analysis has failed to completely exploit the available informational value from offset wells. This has
forced engineers to be more conservative when designing wells and include more contingencies. The result is operators are drilling in a reactive manner, which often led to decisions resulting in performance degradation rather than optimization.
To solve the problem and improve drilling performance in areas of limited/inaccurate offset data, engineers have developed a Mechanical Efficiency Ratio optimization system (MER) that accurately measures the BHA's use of available energy. The modeling tool was tested in several applications and accurately predicted performance including ROP, footage capabilities and dull bit condition. The tool used data and evaluation of rig capabilities, bit/BHA performance, downhole behavior and formation challenges including high-rock strength and interbedded lithologies.
The authors will present three case studies that outline how the software program was used to measure system efficiency to determine which bit would have the highest ROP, total footage capabilities and best dull grade estimate compared to offset runs. The MER will also determine if the system (bit/BHA) or the optimized drilling parameters will improve drilling efficiency.
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.
Cement plugs play a central role in providing hydraulic isolation for oil and gas well integrity. They are routinely required for abandonment purposes, drilling sidetracks and wellbore remedial operations. Despite extensive industry experience from around the world, there are many cases in high-pressure, high-temperature (HPHT) wells where an otherwise straightforward cement plug operation has led to major non-productive time (NPT) resulting in escalation of overall well costs. There are a number of issues that increase risks especially when it involves placement of high-density cement slurries in HPHT wells. Downhole conditions present additional challenges, which make it difficult to do the job right the first time. Whenever a job goes wrong in these conditions there is often an impact apart from the immediate non-productive rig time. In addition to the increase in costs there are other associated impact, e.g. potential loss of downhole barrier with negative implications for safety and the environment.
Many studies and publications have highlighted the risk of unmitigated fluids contamination during placement as one of the most common causes of cement plug failure.
One service company with extensive experience operating in the North Sea has used a model that integrates design and planning combined with a structured, detail-oriented process workflow to reduce surface execution and downhole placement risks thereby increasing the chances of success. The model relies heavily on close cooperation between the service company and the operator. Following the same strategy, this model can be applied in other geographical environments with the core objective of improving quality ensuring the job is always done right the first time. Some case histories, which inspire confidence in the ability to sustain the success rate, are described in this paper.
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.
The value of the mechanical specific energy (MSE) concept to analyze drilling efficiency and bit performance is well established. Recent operator-driven research has concentrated on predicting and maximizing rate of penetration (ROP). The specific energy ROP model has been successfully implemented in numerous high-cost/high-profile environments. To further advance the mechanical specific energy (MSE) concept, an engineering team is developing a methodology to optimize polycrystalline diamond compact (PDC) bit design for the entire hole section based on modeled MSE and unconfined compressive strength (UCS) values.
Traditionally, PDC design engineers adjust cutter density/size, back rake, blade count and nozzle placement to optimize the bit for a specific application. The goal is to maximize ROP and total footage capabilities by minimizing damaging vibrations (axial, lateral, torsional) in a predetermined series of formations. Generally, the selected design has the least potential for vibration across all lithology types. PDC bits can generally drill a homogeneous formation without issues, but when transitioning zones or penetrating interbedded/unexpected formations vibrations can lead to performance degradation and cutter damage.
The industry requires a method to unify bit efficiency throughout the entire section on a meter-by-meter basis. To calculate a bit efficiency factor (Em), engineers are utilizing a sophisticated, integrated, dynamic engineering modeling system. They start with a meter-by-meter correlation between actual borehole lithology and a digitized rock library (UCS). MSE is then calculated using the modeled drilling parameters, torque, and ROP. The resulting two curves are then standardized by calculating the mean value of MSE/UCS fraction to derive a hard value bit efficiency factor. By overlapping the two curves, design and field engineers can identify lithologies that have the optimum correlation then compute the mean efficiency factor for the interval and use it as baseline for the entire hole section.
In the test case study a 38m thick shale section offered the best match, yielding a median efficiency factor. Using the fixed median efficiency factor, engineers
designed and optimized a PDC bit for the entire 16-in. hole section instead of each specific formation. The resulting ROP was significantly improved, as is documented in a case study that will be presented.
Most gas reserves in Algeria are located in unconventional tight reservoirs that typically contain multiple rock types from different depositional systems. Identifying and evaluating these reservoirs is difficult. Permeability predictions are very challenging because of results reliability from different downhole tools, and also by its direct relationship on production and economic impact.
This paper presents a case study that used an integrated formation evaluation approach of tight reservoir during an appraisal stage in an Algerian gas field. The workflow includes:
- Petrophysical model using stochastic analysis to get shale volume, effective porosity and water saturation calculation.
- Hydraulic flow unit zonation using flow zone indicator (FZI) and global hydraulic element (GHE) methods identified from core data.
- Pressure transient analysis from wireline formation tester.
- Mathematical phi-k relationship from core data under confining pressure.
- Synthetic permeability log using previous relationships
In addition to determining reservoir geomechanical properties from the micro frac operation, Synthetic permeability curve were generated in areas of the reservoir that were not core sampled. These predictions were constraint by core data analysis as well as permeability from wireline formation tester.
This methodology was applied in an Ordovician tight sandstone reservoir in the South east Algerian Sahara gas field.
Well intervention techniques and several IOR and EOR methods are sometimes entailing injection of emulsion of water based chemicals and oil into hydrocarbon reservoir layers. The injection depth into each layer usually depends on a lot of different factors that related to reservoir rock and fluid properties as well as the difference between injected fluid's pressure and formation fluid's pressure. For a well completed in multi zones and each zone has its own permeability, porosity, fluid saturation and pore pressure; it is difficult to predict how and up to what end the injection fluid will invade each zone.
A computation model, based on analytical equations of flow in porous media, is developed to simulate bullhead injection of water based chemical solutions into well with multi opened zones. Analytical equations are developed to model fluid penetration radius, injected volume and injection rate for every opened zone during the injection process. Equations describe cooling effect of the injected fluid into hot formation is arranged and simulated to illustrate radial and vertical cooled area during the injection process. An equation is developed to simulate dilution process of chemical concentrated solution during its injection into reservoir layer
This model is very useful when it comes to plan and to design chemical water shut off, sand consolidation, microbial fluid placement, injection of mobility control fluids or any treatment involves of bullheading of chemical concentrated solutions into multi layered reservoir. It can be also used to design many workover applications especially for comminglely completed wells.
Tracking well performance is essential in understanding reservoir behaviour, reservoir management and matching reservoir simulation models with historical data. It results in forecasting reservoir performance accurately. Also, tracking wells performance for multi-fields company with multi joint ventures is important for production allocation for fair company revenue distribution. Regular well testing is required for tracking well performance but in a subsea environment using traditional testing tools such as test separators and slick line downhole gauges to measure production rates and bottom hole pressures, would cost millions of dollars. So these types of tools don't suit a subsea environment therefor other tools to track subsea wells performance are required.
This paper presents tools to tracking subsea wells performance without test separator and by using interventionless tools such as; permanent down hole gauges, venturi and wet gas meter (WGM) with identifying uncertainty in rates measurements with these tools and focusing on measured rate validity techniques by using quality checking (QC) tools such as: a) tracking field production allocation factor b) Sensitivity on measured rates by Integrated asset model (IAM) ,c) using shifted well inflow performance relationship (IPR) and d)Comparing pressure drops along flow paths with initialized selected well flow correlations.
Successful applying of QC techniques on monitored rate of subsea wells for gas field Z allows for identifications of errors in rates measurements and predicting the actual well rate. These assist in simulation history matching and fair distribution to company revenues between JV partners companies.
Tracking well performance is achieved by tracking bottom hole pressures, wellhead pressures, temperatures and rate measurements, this tracking is targeting ;Production allocation ,Reservoir management and assist in history matching reservoir simulation models.
Conventional well testing system (portable test separator package and pressure/temperature gauges run by slick line) is required periodically to obtain accurate and consistent well tracking. However the equipment requires high maintenance, intervention, and time to perform tests, In addition to in subsea environment conventional well testing would cost millions of dollars, due to intervention vessel or floating rig requirement that would maximize operating expense (OPEX) for doing a simple intervention job like well testing. So using conventional testing tools continuously for tracking well performance is not reasonable solution in subsea environment 1,2. This challenge set a concept for completing subsea wells is "well intervention accessibility with zero intervention capability along well flowing life??.
That makes completion design allows tools to monitor well performance and zonal isolation interventionless. Smart completion was a solution for subsea wells by providing two options 3:
Over the past 4 years, there have been several stuck incidents during installation of liners and casing in some wells in Shell Petroleum Development Company (SPDC), Nigeria. In most cases, the sticking mechanism was identified to be differential due to high pressure over balance across some depleted sand intervals. Attempt to free the casing or liner string was successful in few of the cases, while in others, it resulted in either cementing the casing in place at the stuck depth and deploying contingency option where they exist or going through the long, rigorous and expensive process of fishing, plugging back and sidetracking.
Investigations into these incidents pointed mostly to the casing centralization.
During casing installation, a good standoff is required to keep the casing string away from the wall of the well bore to avoid differential sticking and achieve good cement placement. On the other hand, excessive centralization could lead to increased drag force particularly in deviated wells with the attendant risk of not getting the casing to bottom. Prior to casing installation, it is a standard practice to run simulation on centraliser spacing to achieve an acceptable standoff. Bow spring centralizers are commonly used especially for 9-5/8'' casing installation and experience has shown that placement of these centralisers to achieve the acceptable standoff in order to avoid differential sticking as well as good cement distribution has led to having a casing string packed with centralisers thereby increasing the drag force. It therefore became imperative to develop a strategy for optimum centralizer placement in order to achieve both the acceptable standoff to avoid differential sticking and minimum drag. This paper discusses the approach taken to achieve this acceptable standoff with minimum drag force using a combination of Spirolizers and Bow spring centralisers and its impact in reducing the risk of differential sticking.