bluuebunny/crossref_metadata_2025 huggingface dataset:
Determination of Anhydrite in Reservoirs for EOR
Authors: Lopez-Salinas Jose L , Hirasaki George J , Miller Clarence A
Published: September 2011

Alkali in surfactant flooding can sequester divalent ions and reduce surfactant adsorption. When the alkali is sodium carbonate and anhydrite (or gypsum) is present, the anhydrite will dissolve and precipitate as calcium carbonate. An anhydrite level of only 0.1% in the rock is enough to retard the breakthrough of a 1% sodium carbonate solution by approximately 0.7 pore volume, which would greatly reduce effectiveness of a process having surfactants sensitive to divalent ions. Different alkalis will also react with anhydrite.

A methodology is presented to estimate the amount, if any, of anhydrite present in the reservoir. The method is based on brine software analysis of produced water compositions and inductively coupled plasma (ICP) analysis of core samples. X-ray powder diffraction (XRD) can detect anhydrite when it is abundant, but will not be able to detect the low amounts that can still be harmful to chemical EOR.

Produced water and core samples were analyzed from a high-temperature, high-salinity carbonate reservoir, which is a candidate for surfactant EOR. Ten water analyses were obtained from ten wells in five formations. The formation brines ranged from 3-to-20% of TDS. The reservoir rock was mostly dolomite, and reservoir temperature was about 120°C. The saturation index calculated for all formation waters at high salinity (higher than sea water) was positive, indicating over saturation with anhydrite. The saturation index was calculated with ScaleChem for high salinity and PHREEQC, which is limited to lower salinity. The elemental composition of rock samples dissolved in acid was determined by ICP. The mass percent of anhydrite was computed from the elemental analysis.

When these methods were applied to the dolomite reservoir of interest, they strongly indicated that anhydrite was present in sufficient amounts to preclude use of sodium carbonate in a surfactant recovery process.
Salt-tolerant, Thermally-stable Rheology Modifier for Oilfield Drilling Applications
Authors: Wang Jianzhao , Zheng Jun , Musa Osama M. , Farrar David , Cockcroft Bob , Robinson Alison , Gibbison Robert
Published: September 2011

The enhanced performance of drilling fluids, especially High-Temperature, High-Pressure (HTHP) compatibility, will allow more efficient and safer drilling in challenging environments. A novel class of synthetic polymers has been developed as high performance rheology modifiers (viscosifiers) for water-based HTHP drilling fluids. The leading polymer candidate was shown to be an effective viscosifier, with excellent salt-tolerance and thermal stability compared to conventional viscosifiers used in water-based drilling fluids.

This paper presents the basic characteristics of the newly developed polymeric rheology modifier as well as its rheological and thermal stability properties. The rheological properties of the polymers were studied in fresh water, in brines and in formulated drilling fluids. The novel polymer illustrated a similar thickening efficiency and rheological profile (i.e. shear thinning) to xanthan gum. After thermal aging up to 350~400°F (177~204°C) for 16 hours, drilling fluids based on this polymer were shown to maintain excellent rheology and suspension power.
Understanding the Souring at Bakken Oil Reservoirs
Authors: Holubnyak Yevhen I. , Bremer Jordan M. , Mibeck Blaise A. , Hamling John A. , Huffman Benjamin W. , Klapperich Ryan J. , Smith Steven A. , Sorensen James A. , Harju John A.
Published: September 2011

The souring of oil (increasing concentrations of hydrogen sulfide [H2S] gas) from reservoirs in the Bakken Formation has been observed in the field. Souring of oil presents challenges including but not limited to health and environmental risks, corrosion of wellbore, added expense with regard to materials handling and pipeline equipment, and additional refinement requirements. As such, sour oil and gas have lower profit margin (~10% lower price) than traditional sweet Bakken crude.

The understanding of causes for souring in the Bakken Formation and its timely identification are essential for determining the best operational practices and mitigation procedures at this formation. This paper will present an outline of the research goals, a current understanding of souring at the Bakken, and initial findings. Over the course of this project, the series of case-oriented uncoupled compositional reservoir simulations were developed to research the most probable mechanism of H2S generation in the Bakken Formation. The results of this investigation will be correlated in the future with field data from the Bakken oil field operator and laboratory experiments.
Best Practices for Multi-zone Stimulation Using Composite Bridge Plugs
Authors: Lehr Douglas J. , Cramer David D.
Published: September 2011

Treatment isolation using composite bridge plugs (CP) has been practiced for about 18 years in North America and continues to be among the most economical ways to stimulate horizontal and multi-layer vertical wells. Despite this long experience, many end users still experience problems in these applications because of sub-optimal choices regarding product selection, run-in and removal options, and unrealistic expectations regarding plug life in downhole environments.

This paper will identify best practices for using CPs, based on prior technical papers, field experience, and manufacturers’ published data. These practices maximize the chances of successfully installing and removing CPs in multi-zone treatment applications, improving the economics of oil and gas plays requiring multiple stimulation treatments per well.

As multi-zone completion activity increases in regions outside of North America, treatment applications using CPs will also increase in those regions. Realizing the benefits of using CPs in emerging regions will be achieved by learning about best practices from regions with extensive experience in their use.
Silicon-Based Foamants For Foam Assisted Lift Of Aqueous-Hydrocarbon Mixtures
Authors: Koczo Kalman , Tselnik Oleg , Falk Benjamin
Published: September 2011

Foam assisted lift in gas wells, including gas shale, containing both water and hydrocarbon condensates in significant amounts is difficult because the foam is often unstable. The trisiloxane "superspreader" (TS8EOMe) and SiPE-1 to SiPE-6 experimental silicon-based polyether foamants, all with high surface activity, were tested in lab conditions to explore the possibility of using them in foam assisted lift with high hydrocarbon/water ratios. The surface and interfacial tensions and the stability of the aqueous film between an oil drop inside the solution and the gas phase (the so-called "pseudoemulsion" film), were measured and foam tests were conducted with various methods (sparging, foam beating and malt mixer).

It was found that solutions of TS8EOMe form unstable pseudoemulsion film and therefore do not form stable aqueous foams with high amounts of hydrocarbons (hexanes, octane/decane/dodecane, 1:1:1 blend). The SiPE-1 to SiPE-6 surfactants, however, formed stable pseudoemulsion films and their foams were also stable in the presence of these hydrocarbons and therefore they could be candidates for FAL in these systems. The results of sparge tests (the effect of hydrocarbon phase concentration) could be also explained by film stability and the accumulation of oil drops inside the foam. The effects of mixing rate, temperature, aromatic hydrocarbon and the presence of hydrophobic solids were also observed.
Reducing the Risks and Costs of Highly Deviated and Extended Reach Drilling Through the Application of Formation Pressure While Drilling
Authors: Fey Scott , Fareed Abdul , Mansur Hussen , Marzuki Zulkarnain
Published: September 2011

Extended reach and highly deviated wellbores enable operators to intersect multiple reservoir targets with a single wellbore, a capability that would not have been possible had the well been drilled vertically. The driver for drilling these kinds of wells is to reduce the total cost of developing a field. With advances in drilling motors and rotary steerable systems, drilling these types of wells has become common, but there are still challenges in acquiring sufficient formation evaluation data. Often these wells are drilled in already producing fields where depleted zones will be encountered. This, coupled with the high deviation makes wireline conveyed evaluation risky and expensive, in particular since these well types typically require pipe conveyed wireline operations. Logging while drilling (LWD) tools have been able to provide sufficient petrophysical data for the better part of two decades. It is only in recent years that it has become possible to acquire formation pressure data while drilling and thereby provide critical answers to operator asset teams with regards to fluid type, well-to-well connectivity, and depletion trends.

In a drilling campaign in Southeast Asia two highly deviated wells and two extended reach wells were drilled and evaluated successfully using LWD technology both for petrophysics and also formation testing, with an ultimate economic advantage to the operator compared with wireline logging. A formation pressure while drilling (FPWD) service was used to measure formation pressure and record fluid gradients. This paper details the operator's objectives, perceived challenges, operations planning, and the ultimate execution and real time support that made this application of FPWD technology a success.
Latest Development and Project Utilization of Heater Cable in ESP Production System
Authors: Chung Cameron K. , Cox Don , Dalrymple Larry , Yingst Brad , Russell James
Published: September 2011

It has been more than a decade since heater cables were first introduced to facilitate oil production at the North Slope, in Alaska. Since then, the product has spread to acquire a global presence with successful project implementation in a number of countries. There has been increasing interest expressed in using heater cable products in heavy-oil applications given that such products offer significant benefits in reducing fluid viscosity and, consequently, increases the yield rate of horizontal laterals. This paper focuses on the implementation of heater cables, in both technical and project management perspectives. The theories behind the product including electrical and thermal principles in relation to electrical submersible pump (ESP) production systems will be discussed. In addition, project management data such as equipment requirements and field performance through various case histories are presented.
Interpretation of Hydraulic Fracturing Pressure in Low-Permeability Gas Formations
Authors: Kim Gun-Ho , Wang John Yilin
Published: September 2011

The interpretation of hydraulic fracturing pressure was initiated by Nolte and Smith in the 1980s and remains qualitative. An accurate interpretation of hydraulic fracturing pressures, during injection and after shut-in, is critical to understand and improve the fracture treatment in low-permeability gas formations such as tight sand and gas shale. It would provide additional information about the wellbore and better understanding of the reservoir. In this paper, new models for the accurate calculation of bottomhole treating pressure based on surface treating pressure were first developed. This calculation was determined by incorporating hydraulic pressure, fluid friction pressure, fracture fluid property changes along the wellbore, proppant effect, perforation effect, tortuosity, effect of casing, rock toughness, thermal effect, and pore pressure effect on in-situ stress. New methods were then developed for more accurate interpretation of the net pressure and fracture propagation. The models and results were finally validated with field data from tight gas and shale gas reservoirs.
Scale Control and Inhibitor Evaluation of an Alkaline Surfactant Polymer Flood
Authors: Lo Sho-Wei , Shahin Gordon T. , Graham Gordon , Simpson Caroline , Kidd Sam
Published: September 2011

Scale control during Alkaline Surfactant Polymer flooding can be challenging1,2,3 The effective performance of scale inhibitors is a problem, given the high oversaturation expected due to mixing of injected alkali and formation water. Moreover, ASP creates a high pH condition in the reservoir and at production wells. Selecting an effective inhibitor and achieving a long return profile following scale inhibitor squeeze treatment under these conditions can be difficult. This paper describes the studies performed to address the scale management issues for a field where ASP flooding is planned. Scale prediction was carried out and a list of scale inhibitors was screened through performance testing. A number of ASP-specific factors were taken into account for the modeling and testing, including the injected and expected produced chemical concentration, salinity change and chemical compatibility. The results have shown that under these particular field conditions, a conventional penta-phosphonate can provide effective scale control in this field during ASP flooding. Initial core floods indicated that long squeeze life time can be achieved, but the application of the inhibitor in a typical acid form resulted in severe formation damage. A non-damaging formulation was designed by adjusting the inhibitor concentration and partially neutralizing the inhibitor package. The final testing results of the designed inhibitor package show that an effective scale inhibitor squeeze can be attained in the production wells during ASP flooding. More significantly the work demonstrated that the composition of the produced water (% of ASP injection water) producing from a particular zone has a dramatic impact on the potential squeeze lifetimes.
Analysis of Sulphonated Polymers in Oilfield Brines
Authors: Marshall Kirsty , Kyle Mark , Graham Gordon
Published: September 2011

Residual scale inhibitor analysis in produced waters is recognised as an ongoing challenge for many offshore production environments, particularly for the sulphonated co-polymers. This paper builds on work recently presented in SPE 131100 and describes a number of further developments made to enable rapid, accurate, reliable and robust analysis of sulphonated polymers in oilfield brines. This includes more appropriate solid phase extraction (SPE) techniques which demonstrate near 100% retention of sulphonated polymers from brines of different salinities and therefore negate the requirement for dialysis. Whereas the previous paper focused on bench top SPE (solid phase extraction) techniques which demonstrated very efficient assay in synthetic brines, this work progresses and demonstrates the use of the techniques in real produced waters. This paper then advances further to illustrate the progress made in HPLC based techniques including those using GPC based separation coupled with modern highly-sensitive detectors for more routine / automated assay of sulphonated and other polymeric inhibitors. In summary, the paper will present results and methodologies which enable accurate residual assay of sulphonated co-polymers by both benchtop SPE approaches as well as HPLC approaches in both synthetic and real produced waters. These methodologies therefore remove one of the limitations of sulphonated co-polymers compared with other scale inhibitor species and are expected to form the basis of ongoing residual assay for sulphonated polymers in coming years.
Modeling the Effect of Triazine Based Sulphide Scavengers on the in situ pH and Scaling Tendency
Authors: Goodwin N. , Walsh J.M. , Wright R. , Dyer S. , Graham G.M.
Published: September 2011

Amine-based chemicals used for scavenging of hydrogen sulphide will cause precipitation of carbonate scales, under a wide range of conditions. They are effective as scavengers, and have health, safety and environmental advantages compared to other scavenger chemicals. Unfortunately, they significantly raise the pH of all process waters that they are mixed with, and thus exacerbate the scaling tendencies of dissolved carbonate minerals. Calcium carbonate, magnesium carbonate and iron carbonate scales can occur over a wide range of temperatures, pressures, and carbonate concentrations. In many process configurations there is no alternative but to allow the mixing of scavenger with produced water. In those cases, extensive laboratory work is typically required to select an appropriate scale inhibitor. It is usually necessary in such studies to understand in detail the chemistry of the solution and its pH and alkalinity characteristics.

We have developed a modelling methodology which can approximate the effect of triazine type H2S scavengers using an analogue amine as an effective weak base. The effective weak base has a base dissociation constant of the right order compared to monoethanol amine. It therefore simulates the pH effects, and the titration curves of the amine / CO2 / carbonate buffer system that were measured in the lab. Using this methodology we show how the production process has a significant impact on the in situ scaling potentials and how improved modelling and laboratory tests are able to better simulate the field conditions and aid understanding of the process chemistry issues and solutions.
Optimized Formation Fluid Sampling Supports Reservoir Characterization
Authors: Wa Wee Wei , Karim Rahimah Abd , Acuna Pedro Elias , Haddad Sammy
Published: September 2011

abstract

Good quality reservoir fluid samples are critical to ensure the accuracy of the captured fluid composition and thus accurate key reservoir fluid properties’ description, namely GOR, saturation pressure, density, and viscosity. Reliable characterization of reservoir fluid properties during the early stages of exploration and development is critical for understanding fluid composition, estimating reserves, and optimizing production or completion strategies.

Miscibility and time limitation allocated by the drillers have been the main challenges in the open-hole sampling. A quick cleaning process and real time monitoring of contamination level are essential in assuring clean reservoir samples. Fluid cleaning process using conventional openhole sampling technique typically required long pumping times to reach acceptable contamination level.

This work presents an optimized wireline sampling technique with full utilization of downhole fluid analysis applications to address the open hole sampling challenges in an offshore Malaysia field. High quality reservoir oil and water samples were required for detailed PVT and flow assurance analyses. The mud type used was water-based mud, which posts a great challenge particularly for water sampling since the fluids are easily miscible. A focused sampling technique was used to accelerate the mud filtrate cleaning process. Different downhole fluid analysis approaches were applied at water and oil sampling station to monitor the reservoir fluid contamination level. At water sampling stations, pH measurement helped to discriminate the clean reservoir water and water based mud filtrate. While at oil sampling stations, flowing fluid optical density differences was monitored to ensure clean formation oil sample. The methodology and applications of all the techniques are discussed in detailed in this work and documented with actual field data and PVT laboratory results.
Results of a New Coiled-Tubing Assessment Tool
Authors: Stanley R. K.
Published: September 2011

A new non-contact CT assessment system was placed in service in 2010, measuring wall thickness, diameter, ovality, and detecting imperfections in the wall of ferromagnetic steel tubing.

The unit is capable of assessing both new tubing for compliance with API 5ST (Specification for Coiled Tubing)1supplementary requirement SR37, and also in-service tubing for erosion, corrosion and other imperfection conditions. The unit has the advantage of being able to assess the effect of flaws on tubing life via the Flexor programme.

A review of results obtained with the new tool when used to assess both new and used CT will be presented. Knowledge of the condition of the tubing at all stages of its life should be of great importance to owners of tubing when deciding upon future tubing use.
Case Study of Core Bit Wear and its Effect on Core Recovery and Quality during Deep-sea Drilling Expeditions
Authors: Shinmoto Y.. , Wada K.. , Miyazaki E..
Published: September 2011

Scientific deep-sea drilling and coring operations in the Nankai-Trough located offshore Japan have been undertaken to unravel the mechanisms behind earthquakes and tsunami. Throughout a number of expeditions, core sampling runs using an advanced multiple wireline coring system which can continuously core into sections of undersea formations have been carried out. High core recovery and quality are vital to research in undersea formations.

A wireline type rotary core barrel with 10–5/8 inch PDC core bits were deployed in the recent expeditions. However, due to rough sea conditions and severe drilling environment, the PDC core bit cutters were easily worn, causing significantly low core recovery and damaged core samples. The condition of the PDC trim cutters could thus be said to determine the results of the entire operation, showing the need for accurate analysis of the challenges in developing and maintaining drilling equipment and systems.

This study analyzes the bit conditions and how the wear or damage of the PDC cutters affect core recovery and quality. Core quality was analyzed using X-ray-CT Scan image data as a new method of analyzing the quality. The heave motions of the drillship are also shown to affect the core quality and stress or damage while the onset of the core disking phenomenon was also monitored and analyzed.
Use of Salt-Tolerant Friction Reducer for Coiled-Tubing Applications in Unconventional Shale Formations
Authors: Lindsay S. D. , McNeil F. , Sackash M. J. , Bryant J. E.
Published: September 2011

Wells in the oil-and-gas industry continue to be drilled to deeper depths. These wells present complex challenges for completion and intervention operations because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution.

The size of coiled tubing (CT) deployed in deep-reach wells is maximized to achieve a greater level of performance and operational efficiency, while reducing the pressure requirements of equipment. However, weight restrictions, reel capacity, depth, and trajectory of the well can limit the size of CT that can be used.

Using a new cationic polymer friction reducer allowed CT operations to achieve higher rates and velocities while maintaining hydrostatic pressure and lowering surface-treating pressures. The friction reducer has the following attributes: It is salt tolerant, which enables a wider scope of use.Effective at low concentrations.Easily mixed on-the-fly.Compatible with nonionic additives.Can be used up to 200°F.Compatible with shale formations.Extremely rapid hydration.Created for use with water-based fracturing fluids in unconventional shale formations.Gives the customer the ability to reuse flowback and produced water without damage to the formation or addition of fresh water.

This paper describes the new friction reducer and the benefits of using it in unconventional shale formations. Also included is a case history to demonstrate the success of the system in CT drillouts. These field trials provided data to confirm the following benefits. A 25% treating-pressure reduction was achieved; 20% was predicted using an existing friction reducer.Using a friction reducer lowers pumping pressure and hydraulic-horsepower requirements.The system enables increased pumping rates, lowered surface-treating pressure, and higher velocities.Cost savings were achieved and and value was added to the operator.
Well Integrity Analysis in Gulf of Mexico Wells Using Passive Ultrasonic Leak Detection Method
Authors: Johns J. E. , Aloisio F. , Mayfield D. R.
Published: September 2011

Well integrity management presents a wide variety of challenges for the industry today. With aging fields and more complex completion techniques coming into play, more efficient methods of well diagnostics and remediation are demanded. In the GOM, 45% of the wells have sustained casing pressure; therefore, the importance of having a resource that can provide an effective, accurate method of leak detection is abundantly clear.

Typical methods of leak detection today include the use of spinners, temperature tools and noise logs. Mechanical means such as calipers and isolation packers are also employed. While effective for larger leaks, these methods can produce nebulous results with smaller leaks and can be time consuming.

The frequency spectrum a leak produces is a function of differential pressure, leak magnitude, and leak geometry. These properties determine whether the frequency is audible, ultrasonic, or both. Typically, smaller volume leaks with a relatively high differential pressure will generate an ultrasonic signal. Based on this premise, an ultrasonic logging tool was developed and proven that detects frequency spectrums typically produced by leaks. The tool has a series of band pass filters which remove virtually all audible noise associated with tool movement, allowing continuous logging. Because ultrasonic energy will pass through compressed gas and steel, the tool can detect leaks in secondary barriers as well. Further, as ultrasonic energy attenuates quickly, the tool locates leaks with a high degree of accuracy. Using this tool, leaks as small as 0.005 gpm have been quickly located with an accuracy of a foot or less.

This paper will describe a down-hole ultrasonic leak detection tool and provide case histories of where the ultrasonic leak detection tool was used to find leaks that other methods were unable to locate. A comparison of the results from conventional leak detection methods will be discussed as well.
Effect of the Number and Length of Zonal Isolations on Pressure Behavior of Horizontal Wells
Authors: Al Rbeawi S. , Tiab D.
Published: September 2011

Horizontal wells with multiple zonal isolations have become a common completion technique in the oil and gas industry. Sand problems, damaged zones, and water or gas coning are the main reasons for using isolators to sustain or improve oil and gas recovery. However, they have certain effects on pressure behavior of horizontal wells.

This paper introduces new analytical models for studying the effect of this completion technique on pressure behavior of wells with multiple isolated zones. These models have been derived based on the assumption that reservoirs can be divided into multi-subsequent segments of producing and non-producing intervals. Based on the pressure and pressure derivative, the models can be used to estimate the impact of isolators on the pressure behavior. The effects of the number and length of isolators have been investigated for wells having different lengths.

A set of type-curves of dimensionless pressure and pressure derivative versus dimensionless time have been generated for two cases. The first case is for wells in an infinite reservoir having one, two or three isolated zones with three different lengths for the horizontal section and six different lengths for the isolators while the second one is for very long wells in an infinite reservoir. These plots can be used for the type curve matching technique to estimate the number, length, and damaged zones location, segments where sand is produced, and intervals of water or gas coning.

The main finding is that the pressure of these wells behaves similarly for all cases. The dominant effect of the isolators can only be noticed during the early time flow regimes, i.e. during the early radial or early linear. The behavior of the late time flow regimes, i.e. pseudo radial or late linear due to the boundary effects is not affected by the presence of isolators.
Ultra Deepwater Subsalt Reservoir Characterisation: An Integrated Multi-Scenario Approach for Development Planning
Authors: Pippi Olivier , Mayall Mike , Chandler Mike , Dodd Tim , Reid Paul , Taylor Paul
Published: September 2011

Subsea developments of clustered deepwater subsalt fields are challenging both technically and economically. Given the high cost of appraisal wells, the industry tends to rely heavily on seismic technology, pushing the limits in imaging and characterising reservoir through seismic attributes. However, appraisal through seismic in subsalt settings is still uncertain. A fully integrated approach with all available data should be followed to fully describe the uncertainty in order to make an optimised business decision. The objectives of this work are to demonstrate how a systematic methodology was successfully applied to integrate information available from a limited data set, to i) validate the description of the field, and ii) perform a full risk and uncertainty analysis in support of the field development strategy.

This study enabled the building of a solid and integrated description of the field that honours all the sources of data available: seismic, geochemistry, pressures, Drill Stem Test and petrophysics. Analyses from all these data were incorporated into fully flexible static and dynamic models, able to accommodate the entire range of possible geological interpretations, to carry out a rigorous and exhaustive risk and uncertainty analysis.

This work has enhanced the understanding of the subsalt structure complexity and explores the wide range of uncertainty of the reservoirs, resulting in defining an optimised base case development. Alternative scenarios incorporating all the uncertainties identified were generated to quantify their impact and the uncertainty range of the expected outcome in a multi-scenario approach. The thorough risk and uncertainty assessment allowed the identification of the minimum well count to produce the defined resources.

This study offers a sound methodology that proved applicable to characterise a complex field and benchmark its performance against other discoveries. The approach applied is particularly valuable under accelerated development schedules and where seismic characterisation is limited in the description of compartmentalisation.
Application of Hydrajetting Technology Achieves Significant Productivity Increase in Saudi Arabian Gas Producers
Authors: Alabbad E. A. , Solares J. R.
Published: September 2011

Stimulating gas reservoirs, particularly in horizontal producers, has presented a considerable challenge to Saudi Aramco as wellbore accessibility is difficult in wells drilled in deeper formations, with relatively low permeability and high pressure and temperature. Therefore, conventional perforating and stimulation methods have not been as successful as expected when applied in single and dual-lateral completions. Alternative techniques, based on hydrajetting technology, have been recently applied in a number of underperforming horizontal gas producers with excellent results. The technology is used to create slots along the horizontal section and then perform pinpoint acid stimulation treatments. The acid is displaced in the zones in most need of stimulation, resulting in significant well productivity and economic enhancement. This paper provides information about the hydrajetting technology used, and shares details about the successful results and benefits achieved in a cross-section of the significant number of gas producers in which the technology has been applied with an equally positive outcome.
Successful Control of Water Production in Slimhole Completions in a Tight-Gas Sandstone: South Texas Case Study
Authors: Rodriquez Robert , Hall Ryan , Pawlik C.M. (Mike) , Ciezobka Jordan
Published: September 2011

In deep, south Texas fields, water production is an issue that continues to hinder mature fields and significantly impact operating costs and production performance. These wells are slimhole monobore completions with 2 7/8- or 3 1/2-in. tubing cemented in place. This small restricted inside diameter (ID) limited the available methods of shutting off water in slimhole monobore commingled wells.

In the past, the operator would perforate, fracture treat, and flow test each zone separately. Because of this completion practice (long cycle times) along with a shortage of personnel, equipment, and the cost of materials and services, the company has changed its completion strategy. In an attempt to reduce cycle time and cost, a new, more-effective completion strategy was developed, in which the operating company adopted a continuous operation plan to complete all zones (perforate and fracture treat) of interest and then commingle the production on completion of the fracture treatments in the well. Although this next-generation completion strategy or technique was more efficient, it required additional diagnostics to determine which zones were producing water and if the water-to-gas ratio was hindering the well’s performance.

An organically crosslinked polymer (OCP) was successfully placed into the wells, eliminating or greatly reducing excess water production. Although the reservoir parameters were not in the high-pressure/high-temperature (HP/HT) range, the water shutoff required particular attention. Using this technology, the operator reduced water production and disposal costs and increased gas production in some instances.

This paper presents guidelines for completing successful water shutoff based on case histories from the operator’s field. It describes diagnostic methods used, aspects of the required design criteria, operational concerns, and required quality assurance/quality control (QA/QC) testing. Pre and post-treatment water results are also presented.
Managed Pressure Drilling Enables Drilling Beyond the Conventional Limit on HP/HT Deepwater Wells in the Mediterranean Sea
Authors: Hannegan D.. , Kernche F.. , Pena C.. , Arnone M..
Published: September 2011

This paper describes some successful applications of Managed Pressure Drilling on deep exploration wells drilled in the Mediterranean Sea. Building upon successful experience utilizing MPD from HPHT jack-up wells, the Operators transferred the experience across to deepwater exploration projects. This represented the first known use of MPD on a floating rig with water depths up to 1,100 m, HPHT environmentand wells drilled to over 6000 m and BHP of up to17,000 psi.

Extensive engineering, training and development of procedures were carried out prior to spud. MPD was utilized to drill up to drill four hole sections in the same well. Specific techniques were developed to handle floating drilling operations. The resulting benefits associated with MPD led to improvements in drilling performance, and eliminated many of the traditional problems faced on other HPHT wells in the area. MPD has now become an integral part of the well operating philosophy and has established new standards for drilling wells of this type in the area.

Some critical wells were classified as wildcats with considerable pore pressure unknowns, coupled with narrow pore-fracture drilling window characteristic of HPHT conditions. MPD was able to minimize the problems faced on the wells by enabling various techniques to be utilized. These techniques included the use of pressure build up analysis to quantify formation pressures, the application of dynamic flow checks, dynamic formation strength limits, and the application of constant bottom hole pressure during dynamic and static drilling fluid circulation conditions. The planning, development and execution phases of the MPD projects are detailed in this technical paper.
Transient Pressure Analysis of Horizontal Wells in a Multi-Boundary System
Authors: Al Rbeawi S. , Tiab D.
Published: September 2011

Horizontal wells can greatly increase the contact area of the wellbore and the pay zone; so they are commonly applied in oil reservoirs to enhance the production and ultimate recovery, especially in low permeability formations.

The purpose of this study is to develop a technique for the interpretation of transient pressure based on dimensionless pressure and pressure derivative. Type curve matching is one of the techniques that can be used to interpret the pressure data of horizontal wells in finite reservoirs. Starting from very short horizontal wells to extra-long wells, the pressure behavior of the wells has been analyzed for different conditions. The effect of the outer boundaries of the reservoir on the pressure behavior of the horizontal wells has been investigated for different configurations. Rectangular shape reservoirs with different dimensions have been used to study the pressure response in the well.

Five flow regimes have been observed for regular length horizontal wells; early radial, early linear flow, pseudo radial flow, channel flow or late linear flow, and pseudo-steady state flow. While only four flow regimes have been observed for the extra-long wells; linear flow, pseudo radial flow, channel flow, and pseudo-steady state or boundary affected flow. Of course, those flow regimes do not always take place under all conditions. Pseudo-steady state flow is expected to occur after long producing time. A pressure drawdown test was solved using the proposed type curve matching technique.

The study has shown that the effect of the boundary on the pressure response of the horizontal wells and the type of flow regimes depend on the length of the horizontal wells and the distance to the nearest boundary.
A Pilot Test of Continuous Bottom Hole Pressure Monitoring for Production Optimization of Coalbed Methane in the Raton Basin
Authors: Rotramel Jennifer , Bell Morris
Published: September 2011

Pioneer Natural Resources (Pioneer) operates over 2200 Coalbed Methane (CBM) wells in the Raton Basin in Colorado. The wells produce out of two formations: the upper Raton and the lower Vermejo Formations. Many of the wells in the basin are completed in only one formation, with two wells on each pad; each well is completed in one of the formations. A number of the wells in the basin are completed in both formations and have commingled production. Pressure drawdown is critical in coalbed methane production, particularly in wells with large commingled perforation intervals; this is accomplished by lowering the gathering pressures and lowering the annular producing gas-water interface (fluid level) of the wells down below the perforation intervals. Pioneer uses acoustic measurement tools to determine the fluid level in the majority of the wells. However, in some of the wells, particularly the commingled wells, the acoustic tool is unable to measure the fluid level.

A different method to determine the fluid level is to measure the bottom hole pressure and calculate the fluid level using a downhole pressure gauge. To test pressure gauges in the Raton basin, three wells with large perforation intervals were chosen for a pilot test. Pioneer also chose three companies with different components for comparison. The system was designed to be durable and mobile; it was also designed to connect to the existing production monitoring system. The installations for the three wells were successful, though, there were two gauge failures and several pump failures. After the failures were analyzed, and the production of the wells had stabilized with the fluid below the perforations, two of the gauges were moved to other wells. The intermittent acoustic measurements were compared with the pressure gauge information and the two tracked closely; this increased the confidence in the acoustic measurements when values can be obtained. Several of the goals of the pilot project were achieved, including developing the successful system as planned and obtaining reliable bottom hole pressures. There were additional unexpected results from the project; the failure analysis of the pumps lead to a solution for pump problems in the field, and the results provided Pioneer with a visual training tool for the field employees. It is too early to determine if the gauges could be used to more efficiently manage the commingled wells in the field, but a larger dataset of wells may improve the understanding.
Merging Coiled Tubing and Swellable Packer Technologies
Authors: Brooks R. T.
Published: September 2011

For a number of years one of the main areas being developed has been multilateral wells to better access the reservoir. One of the greatest challenges in operating an efficient multilateral well is having control of where any water production is coming from. Effectively managing produced water can bring obvious benefits to the economics of a well. One tool that has not been exploited for this type of application is swellable packers. Coiled Tubing and Swellable Packer technologies were recently combined on a land-based operation in Holland to successfully isolate a water-producing leg of a well lateral. The operator asked for a proposed completion solution after a previous attempt to isolate the lateral had proved unsuccessful.

The proposed solution was designed to straddle the lateral entry/exit with a scab liner, isolated and anchored at either end by water-swellable packers. The straddle was required to seal inside the main bore casing and withstand a differential pressure at well operating temperatures. Swellable packers were selected from the various proven openhole isolation devices available to the industry to provide the zonal isolation required in the multi-zone intervals. This was the first swellable straddle completion in Holland in a watered out, commingled gas environment in which isolation would be contained solely by swellable packers.

The water producing lateral was successfully straddled using two water swellable packers run with base pipe between the two packers. In this application the Swellable Straddle was deployed in conjunction with an additional mechanical packer to anchor the straddle whilst the swelling process in the aqueous environment took place. A subsequent intervention with coiled tubing and a resettable Inflatable Test Packer confirmed the straddle had successfully sealed and had isolated the water producing lateral.

This paper presents a solution to the challenges of isolating laterals using swellable packers and coiled tubing, and how to verify that the junction has been successfully isolated.
World's First Production Logging with Fiber-Optic-Enabled Coiled Tubing (CT)
Authors: Noya V. , Adil A. R. , Wolf K. , Chee S. S. , Stuker J. , Rodriguez F.
Published: September 2011

The coiled tubing (CT) e-line system is ideal to perform real time production logging (PL) in long horizontal wells, however, the wireline cable inside the CT can restrict the pump rate while the large volumes of acid normally pumped could potentially damage the CT pipe's integrity. Furthermore, using two different CT strings, one for pumping acid and another for performing the PL in real time is neither practical nor economical. A common approach is to use a memory PL tool (PLT), with the associated drawback of recording poor quality data or eventual misruns.

To overcome these challenges, a new CT multipurpose system has been developed, allowing real time PL and conventional applications. Leveraging on the telemetry offered by the fiber optic enabled CT (FOECT), already used for downhole measurements while treating in the M field; the new downhole assembly enables the use of standard PLTs in real time mode. At the surface, the converted optical signal is transmitted wirelessly to the PL engineer's portable computer; eliminating the need for conventional acquisition equipment and personnel.

In a world first application, the system was used in a land water injection well, after the stimulation job; obtaining the injection profile log with the same quality measurements as a conventional wireline conveyed log. Moreover, the data demonstrated a uniform injection profile. Additional field applications are also briefly discussed in this paper.

The new multipurpose FOECT reduces the mobilization and logistics otherwise required, as well as the time and cost compared to existing alternatives. This new capability can be extended to other scenarios like offshore or remote environments, where operational costs have a larger impact. Ultimately, the system opens the door for performing diagnosis, treatment and evaluation in a single well intervention mobilization; making CT operations more efficient and providing more data for production engineers.
"The Seven Pillars of Well Integrity Management": The Design and Implementation of a Well Integrity Management System
Authors: Sparke S. J. , Conway R. , Copping S.
Published: September 2011

Today and industry wide, management of well integrity is a common issue, and relates to both old and new producing fields. It is apparent that many fields were not designed with the concept of 'well lifecycle management' and were probably constructed for a life of about 15 - 20 years. A producing well that is 30 years old is quite common (e.g. North Sea production started in 1975) and for wells in locations such as the Middle East some fields are more than 40 or 50 years old.

In line with its expansion and transition to becoming a major independent oil company through its recent discoveries of very large oilfields in Ghana and Uganda, Tullow Oil needed to broaden its existing well integrity policy and practices. This is to fit with a projected 4 to 5 fold increase in oil production in the next few years and increase its well count to over 500 wells.

In order to evaluate the processes in-place, the "Seven Pillars of Well Integrity Management" were defined as the fundamental requirements of an ideal system. These were used to identify gaps in existing practices which were systematically and thoroughly addressed by Tullow.

Tullow now has one centralized well integrity management process that is described in detail through a company policy. This incorporates a software system to collect and manage key construction and operational data from all operated wells. Though monitored and audited from a corporate perspective, the integrity system is run by each asset to suit local operational demands and requirements.

This paper documents the learning process that was experienced by Tullow in their path to deliver a company wide system that would suit varying production scenarios in four different operating environments, with a broad range of cultures and technical challenges and ultimately be expandable to suit the growth of the company.