bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Al-Based Stabilizer for High pH Applications
Authors: El-Monier I. A. , Nasr-El-Din H. A.
Published: September 2011

Sandstone formations are exposed to a variety of high pH fluids, including: hydraulic fracturing using high pH borate gels, alkaline-based chemical EOR methods, water-based drilling fluids and cementing filtrate. High pH values can trigger fines migration, and subsequent loss of permeability and well productivity. An Al/Zr-based clay stabilizer was developed to control fines migration at high pH applications. The objective of this study is to assess the effectiveness of this new stabilizer and compare its performance with commercially available stabilizers.

Laboratory studies were performed using Berea sandstone (8 wt% clays; mainly kaolinite) cores (6 in. length and 1.5 in. diameter). Tetramethyl ammonium chloride (TMAC) and choline chloride were used for comparison as two commercial clay stabilizers. Various coreflood experiments were conducted to determine the effect of the three stabilizers on core permeability (from 64 – 100 md) at various temperatures up to 300°F. In these experiments, a preflush that included 2 wt% stabilizer was injected and was followed by injection of 2 wt% NaOH solution. The later represented high pH filtrate that can invade the formation during any treatment that includes alkaline fluids. The pressure drop across the core was measured and samples of the core effluent were collected. Inductive Coupled plasma was used to measure the concentrations of Al, Zr, Fe, Ca, and Mg.

Lab results indicated that the new clay stabilizer worked effectively up to 300°F. No reduction in permeability was noted in any of coreflood tests using sandstone cores of various mineralogies and initial permeabilities. The concentrations of various cations were found to be a function of core mineralogy. TMAC and choline chloride was not effective when followed by fresh water and incompatible with the high pH fluids. The new stabilizer is environmentally friendly, and can be used in hydraulic fracturing, and alkaline-based chemical EOR methods to mitigate clay related problems.
Unconventional P&A Intervention with Coiled Tubing Below a School Building: Comodoro Rivadavia, South Argentina Case History
Authors: Graterol H. , Calvo T.
Published: September 2011

Oil discovery and development in Comodoro Rivadavia City (South Argentina) has over 100 years of history and more than 2000 wells have been drilled within the city border.

The urban development requires take into account considerations related on Plug & Abandonment (P&A) well status, safety radius and additional special safety conditions. It is important to notice that many of the wells in the city have been pluged and abandoned before the current P&A governmental regulation that was approved in 1996.

A particular case is the Well Ch-1943, which was drilled in 1970, P&A in 1984, and later in 1986 a school was built on top of the well underestimating the associated risks in ignoring the assigned safety radius. Sed School remines active and functioning to this day.

The operator, assuming civic responsibility planned to bring the well to current P&A regulations. The Plug & Re-Abandonment of the well was scheduled to happen during the school summer break between December, 2009 and January, 2010. At that time the challenge was assigned to the P&A Team. The intervention involved many risks and the job needed to be finished in a very limited period of time. Chalenges included well planning, contracts approval, well location restrictions, site preparation to connect the well to the ground level, school roof removal, coiled tubing unit preparation for the well intervention with additional job deck and final surface job and had to be completed without affecting the school building structure.

This document describes the main tasks required to complete the particular challenging intervention complying with the highest safety and quality standards. The Well Intervention was completed successfully in 12 days with a 2″ Coiled Tubing Unit. The total length of the planning/preparation and execution of this project was 46 days.

The Case Story includes: –Well Planning–Well Location–Safety Risk Analysis–Site Preparation–Well Intervention ○Coiled Tubing Rig Up.○Well Calibration – Milling old cement plugs and scrap○Casing Corrosion & Bond Logs Annulus isolation guarantee○Squeeze & Balanced Cement Plugs–Final surface reconstruction

Joint efforts between service companies and the operator was a key factor in achieving the planned P&A results.
Well Interventions in Depleted Gas Wells Made Economical with Use of Small Size (3/4 in.) Coiled Tubing
Authors: Jelinek W. , El-Mabrouk K. , Biezen E. , Leybourne D. , de Jonge R. M.
Published: September 2011

Well interventions in depleted gas wells are often seen as not being economically viable. Since the production rates in these wells are generally low, the pay-back time on the cost of a coiled tubing (CT) intervention could be rather long, making cash flow and earnings not attractive for gas producing companies. Furthermore, due to the low reservoir pressure, introducing fluids in depleted gas wells may cause a water block, formation damage and liquid loading, which can kill the well. Small diameter Coiled Tubing, often called Mini Coil, can overcome these problems, making interventions in depleted gas wells both economical and feasible.

Mini Coil operations with ¾″ coiled tubing were re-introduced in Europe, after 25 years of absence, to offer cost-effective intervention methods for depleted gas wells. Typical Mini Coil operations include small acid treatments, salt plug washes, fluid lifting, inhibition of tubing, etc. For clean outs in wells with a coiled tubing velocity string completion or on offshore installations, where crane limitations do not allow for a standard coiled tubing reel to be used, Mini Coil can be an useful option1.

In this paper the design criteria, applications and the limitations of Mini Coil operations are discussed. Equipment design features and principles for the choice of coiled tubing size and material are presented. Candidate well selection criteria and the benefits of these types of operations are illustrated by case histories in the Netherlands and Germany.

Depleted gas wells, which might not be considered for any further interventions, can now be treated economically again. Mini Coil allows for the use of a compact equipment spread, resulting in cost savings through faster rig-up and rig-down times, smaller footprints, fewer personnel required and fewer truck loads. The small internal volume of the Mini Coil increases the control over the amount of fluid injected into a well, thereby reducing the risk of killing the well during a treatment.
Pushing the Boundaries of Concentric Coiled Tubing Technology To Resurrect Sub-Hydrostatic Gas Wells on an Unmanned Offshore Installation
Authors: Davies A. , Dunning M. J. , Kuchel M. P. , Roberts T. , Taggart M. J.
Published: September 2011

Ravenspurn North is a mature gas field in the Southern North Sea with 42 wells, drilled and many hydraulically fractured in the late 1980s. By 2006 more than half of the wells had ceased to flow and many were flowing intermittently. With ailing wells and consequently falling production rates, the longer term future for Ravenspurn North field was uncertain.

A wireline campaign suggested a common failure mode for many wells that large amounts of proppant had accumulated in the wellbore. Modeling of the potential range of static and dynamic pressure losses caused by this proppant supported a significant enhancement to the remaining gas potential. However, the depths of the wells combined with sub-hydrostatic pressure conditions and large diameter lower completions made achieving cleanout challenging. Furthermore, the target wells were located on unmanned offshore installations with minimal facilities, deck space and deck loading.

This paper details how each of these obstacles were successfully tackled to reinstate a target set of wells. It describes the various cleanout options that were considered, and why Concentric Coiled Tubing Vacuum Technology (CCTVT) was ultimately selected. Prior to this project CCTVT had never been deployed in the North Sea and nowhere in the world at these reservoir depths. The operation was delivered on the small unmanned installation by conducting the world-first boat spooling operation of Concentric Coiled Tubing; rigorously re-assessing deck loadings; and running the operation 100% self sufficient with a maximum of 10 personnel on board.

Finally this paper culminates with a detailed description of the successful CCTVT operations which recovered a total of 2,950 lbs of proppant from three wells to expose the perforations, and unload the wells of liquid. Furthermore, Concentric Coiled Tubing was used to mill out tubing profile nipples and install a packer to hang off 1,200 ft of flush joint tailpipe. Innovative thinking and close collaboration between operator and service companies was required as the ability to perform multiple operations on Concentric Coiled Tubing was in itself pioneering.

Overall this campaign has pushed the boundaries of intervention technology to deliver an extremely challenging project. This has resulted in a more certain future for the Ravenspurn North field, as well as unlocking opportunities in deep depleted gas wells worldwide.
Backpressure Valve for Subhydrostatic Wells
Authors: Xu Z. R. , Tunc G. , Pipchuk D. A. , Morbelli D.
Published: September 2011

Subhydrostatic or low bottomhole pressure wells are wells with large hydrostatic overbalance, that is, the hydrostatic pressure of the fluid column inside coiled tubing, drillpipe, or similar well intervention means is greater than the wellbore pressure at the corresponding vertical depth. The number of subhydrostatic wells is growing as more and more fields mature. Consequently, there is an increasing number of interventions required for these wells to improve and/or optimize their production. U-tubing of the fluid column is a very common and uncontrolled phenomenon during interventions in subhydrostatic wells that can cause problems. In this paper the focus will be on coiled tubing interventions; however, the same basic principles apply to other areas as well.

A backpressure valve (BPV) is a device that is used in subhydrostatic wells to hold the fluid column inside coiled tubing to prevent U-tubing. The BPV compatibility with other components in the toolstring is a critical operational requirement. Following recent tests conducted with the BPVs readily available in the market, it has been shown that these are not appropriate for a number of applications. One example is an application involving pressure pulse telemetry. For pressure pulse telemetry, conventional BPVs either cannot pass the pressure signals or greatly attenuate the magnitude of them.

A backpressure valve that is fully compatible with pressure pulse telemetry has been developed and will be presented in this paper. The root cause of why the conventional BPVs were not able to transmit pressure pulse will be discussed using the results from fundamental physics, computational fluid dynamics analysis, and lab and filed experiments. Finally, a typical set of results from a field trial using the new valve will be presented.
Inversion of DTS Logs To Measure Zonal Coverage During and After Wellbore Treatments With Coiled Tubing
Authors: Tardy P. M. , Ramondenc P. , Weng X. , Burgos R. , Baez F. , Ganjeh K. Yekta
Published: September 2011

Distributed temperature sensing (DTS) is a fiber-optic technology that provides continuous temperature profiles along the length of a well. When placing the fiber inside a coiled tubing (CT), one can monitor the temperature evolution while pumping, as well as during a shut-in period. This evolution, in turn, yields some indications about the fluid placement performance or zonal coverage. So far, interpretation of such DTS traces has mostly been qualitative. The work presented here demonstrates how DTS data can be used, coupled with an inversion algorithm and a forward model of fluid injection into a reservoir, to quantify the intake profile of treatment fluid along the wellbore. Recent field cases of matrix acidizing treatments in carbonate reservoirs are analyzed to illustrate the workflow and how it may yield valuable information.
Skin Monitoring And Well Testing Utilizing Fiber Optic Telemetry Enabled Coiled Tubing
Authors: Shaheen Tarek , El Fattah Mohamed Abd , Dilling Lambert , El Rahman Sayed Abd , Anwar Emad , Noya Vidal , Elsherif Tamer
Published: September 2011

For the last several years, viscous pills, polymer based, were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. These polymer pills have negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well A-1 was producing 300 bpd (Gross) which declined dramatically after a workover operation which included the viscous polymer pills to produce only 20 bopd.

An engineering study was carried out to identify the main reason for the decline in the production. Several experiments were performed in the lab in order to simulate the filter cake using formation samples and evaluate the effect of the polymer being injected on the sandface permeability. An engineered solution was designed to break the polymer subsequently pumped in the formation and stimulate the matrix in order to recover and enhance the oil production. The remedial work was executed using a Fiber Optics Telemetry Enabled Coiled Tubing (FOTECT) system to optimize the treatment leveraging on downhole real time measurements.

This paper describes the first application of FOTECT in sandstone formations, involving:

1. The sandstone matrix stimulation operation.

2. Measuring both bottom hole pressure and temperatures at static and dynamic conditions during the entire operation.

3. Accurate depth correlation to achieve optimum placement of the treatment fluids

4. Monitor the chemical reactions in real time of the engineered treatment fluid.

5. Monitor the diversion performance during Sand Stone stimulations and the timing required for efficient reactions.

6. Qualitative production allocation of the interval as a response to the treatment fluids

7. Evaluation of the skin value real-time while executing matrix stimulation.

8. Pressure transient analysis in real-time enabling the standard output of a well test (permeability, skin, Pressure, and reservoir boundaries).

The experience demonstrates that use of real-time downhole measurements during the CT treatment allows: a) the evaluation of the well performance before and after the treatment, b) enables optimization of the treatment as it is executed, based on the formation response, enhancing the chance for a successful intervention, and c) provides an added alternative to perform a well testing operation right after the treatment, thus, obtaining valuable information to update the reservoir model.
Redefinition of Well Interventions in Naturally-Fractured Carbonate Reservoirs through Real-Time Coiled Tubing-Deployed, Fiber Optic Monitoring
Authors: Aviles Rodrigo , Flores Jose G. , Martin Frederic , Diaz Alan , Davila Luis E. , Monroy Rafael R. , Beltran Jorge , Moreno Angel R. , Martinez Armando
Published: September 2011

The South Region of PEMEX in Mexico produces 530,000 bopd from mostly mature, naturally-fractured carbonate reservoirs. The majority of the well interventions in the area present complications, due to a combination of extreme operational conditions, variety of reservoir rocks and fluid environments, and complex well configurations required to produce from large intervals in different flow units, many supported by active aquifers and secondary gas caps, that eventually reduce the production of oil as the water production and gas production increase. Rigless stimulation and maintenance well operations have been recognized for decades as efficient and cost-effective production enhancement enablers in the area. As the fields mature and the well interventions become more challenging, there is a higher demand on the operator side to successfully pinpoint the intervals and execute treatments that overcome unknown downhole parameters with confidence, maximizing success and avoiding additional remedial work.

A new approach, incorporating real-time, coiled tubing-deployed, fiber optics monitoring, was implemented in three well interventions in southern Mexico. These included: (a) the isolation of a high-water producing interval in a low-pressure reservoir using an inflatable packer; (b) a matrix stimulation requiring the accurate placement of fluids and diversion stages; and (c) the perforation and testing of several intervals in a gas injector well.

Real-time down-hole measurements of performance have been found to be an excellent option to improve the success rate in the well interventions in southern Mexico, allowing capturing unique quantitative feedback from the well, to be able to act with a greater degree of precision to increase production. Coiled tubing-deployed fiber optics proved to help the operator to improve efficiency and to optimize intervention performance with confidence in real time.
Success Story: Improving Reservoir Monitoring to Increase Production in Offshore Marginal Oil Field
Authors: Pramboeidi Sri Khresno , Subiantoro Edy
Published: September 2011

Mengkapan is a mature offshore oil field in the Malacca Strait PSC, located in central Sumatra, Indonesia. First oil flowed in 1986. The production wells produce multiple sands commingled with simple ESP completions. Cumulative oil production at the end of 2010 was 35 MMSTB, and the current recovery factor is around 50%.

Over the years, as oil rates declined and water cuts increased, the team ran production log campaigns to monitor the oil rate and water cut of sand. These logs revealed the occurrence of cross-flow and oil-blocking, which was attributed to differences in permeability and pressure between the sands. The log results led to workovers to isolate high water-cut sands by setting production packers. But after more years passed, the point was reached where there were no more zones to isolate with packers, and the team was forced to consider well abandonment.

Rather than abandonment, the team changed their mindset from "there is no remaining oil" to "there is by-passed oil and we can get it". The chosen technique was to squeeze-cement high water-cut zones and re-perforate by-passed oil sands identified from cased-hole logs.

In ME-02, massive cross-flow between high-permeability sands seen in the production logs did not matter, because the suspected by-passed oil sands were the lower permeability sands at the top of the perforated intervals which were unaffected by cross-flow. The Carbon-Oxygen log suggested by-passed oil in the upper part of some sands. Next, all perforated intervals were squeeze-cemented, using a technique fine-tuned with the team’s knowledge of cross-flow. Then, the by-passed oil zones were re-perforated, and the well was completed and put on-line.

Prior to squeeze cementing and re-perforation, ME-02 well produced 9000 BFPD, 45 BOPD. After the workover, the well produced 2000 BFPD, 104 BOPD. The budget was USD 660,644.00, but only 60% of the budget was used. It paid out in two months.

This paper tells the failures by relying on a single tool and the success story in ME-02 to increase the value of a workover (reduced operation cost and increased oil gain), including the concept, the data gathering, and the field operation.
Well Production Enhancement Results with Inflow Control Device (ICD) Completions in Horizontal Wells in Ecuador
Authors: Vela Ivan , Viloria-Gomez Lumay , Caicedo Ricardo , Porturas Francisco
Published: September 2011

Reservoir performance is dependent upon system interaction between the completion hardware, the wellbore reservoir section and its connection to surface.

A-priori condition used to design a robust completion solution are housing units capable of draining and collecting fluids along the entire completion length and simultaneously produce oil while delaying more mobile fluids. Therefore the completion design should focus on: Those scenarios that are expected to have greater impact in the producer wells: These include for example PI increase, adjusting drawdown pressure, flux balancing, delaying early entry of high mobile water or gas along the entire completed interval, well clean-up through time and extending well production life.Wether it is expected to accelerate initial production or balanced management of the field. The goal in both cases is to achieve efficient area drainage and uniform sweep while not leaving by-passed oil in the ground.Whether the contingency plans are for, alternative re-completions or preparing the wellbore for future operations such as EOR related activities to stimulate production from much lower oil residual saturations.Having hardware ready that allows changes in operational modes from producer to injectors or viceversa, or permits installation of slim hole units, technologies to enhance porosity or permeabilty, reduce viscosity and mobility ratios, implement fine reservoir characterization models, avoid reaching ultra-high WCUT too soon or to implement intermediate EOR operations to slow down this tendency.

In Ecuador, an operator has completed several wells equipped with ICDs, in both consolidated and non-consolidated reservoirs and with variable rock and fluid properties including viscosities varying between 4 to 47 cP. This paper describe the combination of ICD design, geo-steerirng, calibration with real-time log data, installation procedures and fluid historical production results through time.
A Fully Coupled Geomechanics and Fluid Flow Model for Well Performance Modeling in Stress-dependent Gas Reservoirs
Authors: Salah El-Din Ahmed , Elbanbi Ahmed H. , Abdelwaly A. A.
Published: September 2011

Predicting the performance of wells in stress-dependent gas reservoirs can be quite challenging to most conventional reservoir engineering tools. In this paper, a fully coupled geomechanics and fluid flow analytical model was developed for modeling well performance in stress-dependent gas reservoirs. For tight and unconsolidated gas reservoirs that exhibits variable formation compressibility, reservoir compaction, and stress-dependent properties deterioration such as permeability and porosity, the geomechanics effect may not be ignored. All these physical contributes play an important role on well performance. The coupled model considered all these contributes and evaluate their impact on well productivity. The model also accounts for the effect of the transient flow period and variable producing conditions in addition to the effect of non darcy flow in gas wells.

An optimization algorithm was used with the coupled model to estimate original gas in place and performance characteristics for each layer in case of multilayered gas reservoirs.

Different simulation cases and selected examples from gas wells producing from stress dependent gas reservoirs are used to illustrate the coupled model application. The results from this study indicates that a fully coupled geomechanics and fluid-flow modeling approach is necessary for analyzing highly stress-sensitive gas reservoirs
Evaluation of A New Liquid Breaker for Polymer-Based In-Situ Gelled Acids
Authors: Aksoy G.. , Gomaa A. M. , Nasr-El-Din H. A. , Wang X.. , Boles J.. , Cawiezel K..
Published: September 2011

In-situ gelled acids with Zr4+cross-linkers utilize a solid breaker to reduce the viscosity of the gel at pH range of 4–5. A literature survey confirmed that solid breakers caused a premature reduction in the fluid viscosity resulting in a less than desirable productivity. Therefore, an effective liquid breaker that is based on tetrafluoroboric acid was developed. As pH increases, the liquid breaker releases fluoride ions, which will combine with the cross-linker, Zr4+. This study was conducted to evaluate this new breaker system under the following conditions: breaker concentration (0–200 ppm), and acid injection rate (0.5–10 cm3/min).

The effect of the new breaker on the rheological properties of in-situ gelled acid was examined using a HPHT rotational viscometer. A coreflood study was conducted to follow the propagation of acid and cross-linker inside the limestone core. Samples of the core effluent were collected and the concentrations of calcium, zirconium, and acid were measured. Permeability enhancement and location of the residual gel were determined using CT scans.

The pH profile during neutralization confirmed that the crosslinking of the polymer occurred at a pH value of 1.8. At a pH of less than 2, doubling the breaker concentration did not affect the viscosity of the acid. However at a pH of greater than 2, the viscosity of acid was reduced by 30%. At a breaker concentration of 0 ppm, the appearance of Zr in the core effluent sample was delayed by 0.25 PV compared to the reaction product, while at 100 ppm Zr was delayed by 0.75 PV. At 200 ppm breaker, no Zr ions were detected in the effluent samples. As the breaker concentration increased, more Zr remained inside the core, as ZrF4, which is water-insoluble. Increasing the breaker concentration from 100 to 200 ppm reduced the final normalized pressure drop by 50% at injection rate of 2.5cm3/min. Permeability reduction due to gel was reduced by increasing the acid injection rate. Therefore, the acid solution with the liquid breaker should be injected at high injection rates.
Effect of Heterogeneity on Production Performance in Low Permeability Reservoirs
Authors: Kewen Li , Yangtze U. , Ronghua Xie
Published: September 2011

It is well known that heterogeneity is one of the most important factors in affecting production performance. These include oil production rate, oil recovery before water breakthrough, water cut, etc. However, it has long time been a challenge to correlate the heterogeneity and the oil production performance quantitatively, especially in low permeability reservoirs. To this end, fractal dimension inferred from mercury-intrusion capillary pressure data and other parameters were used to quantitatively characterize the heterogeneity of rock in this study. Over 100 core plugs were sampled from different wells in a low permeability oil reservoir. Routine and special core analysis tests were conducted in these core samples with a permeability ranging from less than 0.1 to over 100 md. Correlation between heterogeneity and oil production performance was investigated at both the microscopic (core) and macroscopic (well and reservoir) scales. The results demonstrated that the fractal dimension was correlated with the production performance at microscopic and macroscopic levels. The oil production rate and the water breakthrough time show an inverse relationship with fractal dimension, while the water cut shows a direct relationship with fractal dimension.
Prediction of the Efficiency of Impulse-Wave Impact Application in the Well Treatments
Authors: Zamakhaev V. , Miftakhov S.
Published: September 2011

On the long-developed fields structure of residual stock is deteriorating and to maintain the highest possible rate of recovery different technologies for the rehabilitation of wells and enhanced oil recovery are applied. Hydraulic fracturing or explosive effects often lead to significant heterogeneity complicates the process of extracting oil. Discontinuities positive effect has short duration that lead to search for other approaches to solving this essential issue.

The impulse-wave impact (IWI) technology is an advanced method based on a combination of impulse effect (water hammer), which creates in layer longitudinal and transverse waves of seismic frequencies, and physicochemical effect. However, such aggregation is not a simple combination of these influences, but should be considered as a single process consisting of preparation for the impulse impact by directional changes in the adsorption conditions in a large reservoir volume and impulse action.

To achieve high technical and economic indices of reserve development is necessary to define scientifically grounded criteria for the organization of events; usage of large-scale geological field data representing objects for work and establishing specific technical recommendations for the IWI technology appointment and the optimal treatment condition for a particular well.

This paper deals with a predictive modeling, carried out within the bounds of a systemic approach to the selection of objects, appointment of manufacturing operations, the overall organization recovery works in water injection wells and exploitation wells as an example of fields in Western Siberia.

Predictive modeling of formation pay zone treatment process was conducted based on the accumulated initial geological, geophysical and technological information using the method of factor analysis. The advantages of this approach are particularly evident in the first stages of a trial simulation with the need to incorporate in the model of a large number of factors and the lack of "observations".
A Multimode Inversion Methodology for the Characterization of Fractured Reservoirs from Well Test Data
Authors: Lange Arnaud , Bruyelle Jérémie
Published: September 2011

Optimizing the exploitation of fractured reservoirs requires a reliable characterization of the most influential heterogeneities on flow properties. To this end, reservoir simulation models should remain interpretable in geological terms. Workflows are available (i) to construct geologically-realistic models of fracture networks, (ii) to turn these models into simplified conceptual models usable for field-scale simulations of multi-phase production methods. However a critical step remains that of characterizing the flow properties of the geological fracture network. The multiscale nature of fracture networks and the associated modeling cost impose a scale-dependent characterization: (i) multi-scale fractures are characterized in local dynamic tests area, e.g. well test drainage area, through the calibration of geologically-realistic Discrete Fracture Network (DFN) models and accurate local flow tests simulations; (ii) large-scale faults are characterized through reservoir-scale production history simulations. This paper presents an efficient "multi-mode" inversion methodology to facilitate the characterization of fracture properties from well test data. The fracture model is optimized sequentially according to different modes of deformation. First, the parameterization is defined such that the fracture model is deformed as a whole (mode 1), then S fracture sub-sets are defined accordingly to their sensitivities to well test data (mode S), where S is increased sequentially. The optimization is performed via an original evolutionary algorithm that has been coupled with a 3D DFN flow simulator. An application is presented on a fractured reservoir model having two facies, four fracture sets and involving a horizontal well test. The characterized fracture properties are the mean size properties, mean conductivity and facies-dependent fracture densities.

This "multi-mode" inversion methodology is shown to be much faster to characterize physically meaningful and data-consistent fracture properties, compared with a direct optimization application on all model parameters. This methodology facilitates the characterization of fractured reservoirs flow properties.
Workflows and Methods to Optimize Well Construction through a Collaborative Environment
Authors: Raja Hamayun , Carpenter Glenn , Oliver DeShawn
Published: September 2011

Since the advent of improved telecommunications in the early 1990s, operators and service providers have sought to reduce non-productive time (NPT) through remote operation capabilities delivered using real-time centers (RTC) or with a combination of remote expertise and computing power to monitor operations and provide technical advice to the field. Although the RTC concept has delivered tangible benefits, these benefits were less than anticipated and have been more difficult and expensive to implement than initially expected. Currently, advances in RTC and research and development (R&D) focus on integrated workflows to address specific problems. The goals are to safely reduce NPT, risk, and uncertainty to improve decision making and performance of the entire operation and to facilitate the prospect of remote, automated operations.

This paper presents two examples of workflows (i.e., geosteering and stimulation workflow) that can enhance operations for both the operating and the service company. This paper will also discuss some of the challenges in applying these integrated operations. These workflows, also known as 3-D collaborative environments, demonstrate the use of real-time information to model, measure, and optimize field performance, efficiency, and safety through the use of remote, closed-loop, real-time data and knowledge transmission. The 3-D collaborative environment for the stimulation workflow allows operators to use the data available from several product service lines to make decisions in real time that will improve production rates and reduce NPT. This particular workflow allows the use of geological, geophysical, stimulation, and micro-seismic data to visually understand actual fracture growth during a stimulation treatment. Knowing the location of micro-seismic events as they relate to geological boundaries and surfaces allows the fracture engineer to quickly make decisions during pumping to reduce undesirable results. The "geosteering workflow" provides a 3-D collaborative effort between the customer's geological and geophysical software and the service company's geosteering software. This workflow resolves structural solutions in complex geological situations in real time, where the solution cannot be resolved by either system alone. Structural grids, faults, well picks, fault picks, and control points move between the software using a WITSML proprietary code. The results include fewer sidetracks, redrills, and maximizing reservoir exposure to the wellbore.
Well Test Analysis of Medium-Rich to Rich Gas-Condensate Layered Reservoirs
Authors: Kgogo T. C. , Gringarten A. C.
Published: September 2011

Gas condensate reservoirs exhibit complex flow behaviours when the bottomhole pressure drops below the dew point pressure. This is due to the creation of condensate banks around the wells, which also induce losses in productivity. Multi-layered reservoirs add to the complexity as a consequence of contrasting properties in the different layers. Understanding the pressure behaviour of layered systems is important to determine reservoir parameters, predict well performance and maximize hydrocarbon recovery.

This paper investigates well test behaviours below the dew point pressure of vertical wells in medium-rich to rich gas condensate layered reservoirs, with and without crossflow. 3-D compositional simulation was used to investigate wellbore pressure responses below the dew point pressure, and in particular the effect of condensate drop-out on the productivity of the different layers.

It was found that composite well test behaviour due to condensate bank, and multi-layer behaviour are superimposed, with the condensate bank appearing on top of multi-layer effects on the pressure derivative. In a two-layer reservoir, the condensate bank radius is always greater in the most-permeable layer. Near-wellbore liquid saturation is lower in the least permeable layer at early times; becomes equal to that in the most permeable as production rate and time increase and pressure in the two layers stabilizes; and increases above that of the most permeable layer at later times when there is crossflow. Eventually, the least permeable layer becomes choked by its condensate bank and all production occurs through the most permeable layer only.

Results from this study were used to understand well test data from the E-M field located offshore South Africa and to repair a vertical well in that field.
Torque and Drag Software Model Comparison: Impact on Application and Calibration of Field Data
Authors: McCormick John E. , Frilot Melissa , Chiu TzuFang
Published: September 2011

With the number of extended-reach wells steadily increasing, software modeling has become a commonplace and essential process during a well's planning phase. Over the years, numerous computer programs have been developed to predict torque and drag (T&D) forces experienced during oilfield drilling and completion operations. Accurate prediction of T&D forces can reduce serious drilling operation risks such as buckling, pipe failures, box swelling and the inability to get liners and casing to total depth (TD).

Most, if not all, industry available T&D software programs allow users to manipulate inputs such as friction factors, mud weight, and string component parameters, such as pipe weight, grade and dimensions. While the ability to alter the inputs in the T&D model is a practical necessity, the possibility of unknowingly impacting the calculations is an ever present danger. In addition to a thorough knowledge of how to input well parameters and analyze outputs, it is crucial for program users to question the reliability of each program and to understand the impact that changes in inputs have on the model's outputs.

This paper will describe the technical differences between two T&D modeling programs, the underlying calculations, and the practical implications in terms of calibrating the two models to the same sets of field data. This paper also endeavors to increase knowledge and competency for T&D software users in the oil and gas industry.
Optimizing Horizontal-Well Hydraulic-Fracture Spacing in the Eagle Ford Formation, Texas
Authors: Mendoza E. , Aular J. , Sousa L.
Published: September 2011

The successes of horizontal-well completions in the Eagle Ford formation have increasingly attracted interest within the oil and gas industry. An improved stimulation technique using new fluids and proppants has resulted in better zonal coverage through improved diversion and tagging. Low-permeability reservoirs attract increased attention from oil companies because of increased demand and limited opportunities in conventional (higher-permeability) reservoirs.

This paper presents a case study of a horizontal well in the Eagle Ford reservoir. The reservoir rock is considered 100% dolomite with 9 to 12% porosity and permeability of 4.0E-5 md. Vertical wells in this area, even being hydraulically fractured, still produce below economic limits. Horizontal wells with multiple, transversal hydraulic fractures have shown to produce more than vertical wells and have been successfully applied in low-permeability reservoirs in Texas.

The principal objective of this paper is to show the analysis and selection process of a completion design for a new well to evaluate the reservoir parameters and determine the optimum hydraulic-fracture completion design, including fracture stages and an economics review. In this work, 3D fracture growth and conductivity models were calibrated and optimized using the existing fracture post-job reports of neighboring wells completed in the Eagle Ford reservoir.

This workflow could be applied to any low-permeability reservoir with the intent to optimize the number of hydraulic-fracture stages on a new horizontal well, minimizing the stages’ interference and maximizing the expected net present value (NPV). This workflow demonstrates an effective methodology for capturing essential characteristics of Eagle Ford reservoirs and offers a quantitative means and platform for optimizing shale reservoirs.
Hybrid Drill Bit Improves Drilling Performance in Heterogeneous Formations in Brazil
Authors: Thomson I.. , Krasuk R.. , Silva N.. , Romero K..
Published: September 2011

Geologically heterogeneous (mixed) formations pose a significant challenge to drillers in terms of drilling performance. Shale and other soft and plastically behaving rocks favor the use of PDC bits, while hard and abrasive sandstone with hard cement stringers favors roller cone bits.

With recent advances in PDC cutter technology it is possible to combine the best features of both bit designs to drill formations that constantly fluctuate between hard and soft lithology, and often without notice. This has been achieved by using a basic PDC bit design and replacing the secondary blades on the periphery with rolling cutters equipped with tungsten carbide inserts. The resulting product is frequently referred to as a hybrid bit. A hybrid bit allows the maintenance of overall penetration rate (ROP) at much higher levels than that of a roller cone or PDC bit alone. Avoidance of the necessity of tripping for bits due to formation changes or for premature bit wear is clearly advantageous. Experience from the USA, where up to a 35% reduction in drilling time has been achieved in heterogeneous formations, prompted the use of this technology in Brazil.

A similar challenge exists in NE Brazil with geologically interbedded sandstone and shale sequences. The challenge was to drill the interval with improved ROP and with reduced vibration while simultaneously reducing the need for bit change related trips. Experience in Brazil to date shows that by maintaining a consistent ROP in interbedded formations, aided by better toolface control due to lower torque fluctuations, a 44% decrease in total drilling time has been achieved while run length more than doubled. Future evaluation of this new technology extends to Brazil offshore basins (Campos, Santos, and Espirito Santo) where Albian and Aptian carbonate reservoirs have different lithologies but the challenges of geological heterogeneity are similar.
Improved Characterization of Non-Linear Injectivity Formation Damage from Coreflood Pressure Measurements
Authors: Vaz A. S. , Bedrikovetsky P.. , Fernandes P. D. , Furtado C.. , de Souza A. L.
Published: September 2011

PWRI and seawater injection may result in drastic injectivity decline. The reason is solid and oily particles, which are captured by rock from injected water causing steep permeability decline. The reliable injectivity decline prediction, allowing for injector stimulation planning and design, is based on mathematical modelling with well-known values of two model functions of filtration and formation damage.

Previous works proposed the method to determine two injectivity damage constants - filtration and formation damage coefficients - by measuring pressure drops on the core and also on its first section (so called 3-point-pressure method). Dimensionless pressure drop, which is proportional to skin factor, was proven to be linear with time, allowing for unique solution of the laboratory data matching problem. Yet, often the skin growth curves are non-linear. It is explained by the retained concentration dependence of filtration and formation damage functions. In the previous works, the physics reasons for filtration functions to be linear have been analysed. Therefore, the filtration coefficient was assumed to be linear function of retained concentration. The inverse to the formation damage function was assumed to be quadratic polynomial of retained concentration, which caused non-realistic skin prediction and non-unicity of the matching problem.

In the present paper, the inverse to the formation damage function was assumed to be monotonic power function of retained concentration, allowing for unique matching with laboratory data. An analytical model developed accurately describes pressure data of several coreflooding tests. In order to validate the proposed method, the pressure drop was measured on the second core section on top of the first section and the overall core. The measured data were compared with modelling tuned by the data from the first section and the overall core. Good agreement between the measured and fully predictive modelled data was observed, which validates the proposed method.
Production Experience in the BC-10 Parque das Conchas Development Offshore Brazil
Authors: Souza B.. , McFee K.. , Caillaux P.. , Langedijk R..
Published: September 2011

July 2009 saw the start of production from Phase 1 of the Parque das Conchas project, an offshore cluster development located in license block BC-10, 120km off the Espirito Santo coast in the Campos Basin, Brazil. Phase 1of the project consists of three diverse, small fields with a wide range of oil types, tied back to a Floating Production Storage and Offloading vessel (FPSO). The eight producers located in the Ostra and Abalone fields flow to a subsea artificial lift manifold (ALM), where gas and liquids are separated, with the liquids pumped to surface via caisson-based electrical submersible pumps (C-ESPs). The two producers in the Argonauta field flow to a second subsea ALM, where the multi-phase fluids are pumped via non-separated C-ESPs. The produced gas is re-injected into a gas disposal well in the Ostra aquifer until export facilities are available.

On start-up, a few key uncertainties remained on the performance of the wells in the field, particularly related to initial production rate, well connectivity and the potential for fines migration inside the formation and the gravel-packs. A surveillance plan was developed before first oil to assure integrity of the wells and to determine and improve the performance over time. The plan was linked to the available measurements of permanent down-hole pressure and temperature gauges (DHPTG) and subsea multi phase flow meters (MPFM) in most wells. A schedule of interference tests, individual well tests and pressure build-ups was planned for the initial production phase.

Conclusions drawn from the surveillance plan are based on the analysis of the whole range of collected data, matched to single well and integrated system models. This paper will describe the logic of the surveillance plan and the experience gathered from the wells during the first year of production from the Parque das Conchas fields and how this information has been used to optimize production.
Production Logging in Horizontal Wells: Different Deployment and Data Acquisition Methodologies in Open-Hole and Cased Completions
Authors: Torne Juan , Arevalo Francisco , Rourke Marvin , Jay Phil , Kwong Shan
Published: September 2011

The horizontal wells drilled during the last few years are coming to a mature state in different fields and locations. This maturing has created the requirement to evaluate the performance of the wells and determine water sources for proper reservoir management.

In horizontal-well tool deployment, multiple sensor data acquisition and the interpretation of these results is a challenge particularly when there are long intervals of open-hole completions and where fractures are often encountered. The horizontal cased-hole completions use multiple downhole valves and external packers to provide isolation between intervals.

This paper reviews the two primary deployment techniques of coil tubing and tractor conveyance and highlights their advantages and limitations. In the paper, we propose a general guideline for their use.

The use of different sensors and their application is reviewed, providing recommendations particularly for low flow-rate conditions. Two interpretation methodologies are evaluated and results are compared along with the interpretation from other sensors.

The value of integrating of all available information and the value of different data acquisition and evaluation techniques is presented as well in the paper. The conclusions highlight the operational considerations, the data interpretation, and added value in the evaluation of well performance to maintain production and improve reservoir management.