bluuebunny/crossref_metadata_2025 huggingface dataset:
Porosity Determination From NMR Log Data: The Effects of Acquisition Parameters, Noise, and Inversion
Authors: Bachman H. N. , Crary S. , Heidler R. , LaVigne J. , Akkurt R.
Published: December 2007

An ongoing challenge for nuclear magnetic resonance (NMR) well logging is that the quality and utility of the data depend on the acquisition sequence, inversion parameters, and the logging environment. Some modern NMR logging sequences are intended to be applicable over a wide range of environments, and include measurements of transverse relaxation (T2), polarization (T1), and diffusion (D). But compromises are inevitable for any given NMR technique. For example the overall acquisition time is dictated by operating at "reasonable" logging speeds, so full polarization of long T1 fluids is rarely achieved. Additionally, the inversion process creates interdependencies between T1, T2 and D. These effects conspire to introduce inaccuracies in the reported porosity.

We investigate the influence of acquisition parameters, inversion parameters, and noise on the determination of porosity from NMR data. A key focus is on fluids exhibiting the extremes of T1, T2 or D such as light hydrocarbons, gas, water at high temperature, or heavy oil. We make this investigation by three methods. The first method is to calculate a porosity sensitivity curve as a function of T1, T2 and D for multiple acquisition modes. The second method is to invert simulated NMR echo data. Lastly, we compare real NMR log data porosities with other porosity logs in fields exhibiting long T1 constants. In all three cases, we show how porosity is under-or over-estimated beyond the expected accuracy based on random noise alone. The results are discussed in terms of what measures can be taken to identify and minimize these errors.
Life of Well Isolation Implemented in Major North Sea Development
Authors: Hunter Liz , Kinnaird Bill , MacLean Kerry
Published: December 2007

The Buzzard field operated by Nexen is the largest oil discovery in the North Sea since the early 1990s. About 27 production wells, of approximately 9,000 ft total vertical depth (TVD), will be drilled during the field life. Maximized life of well isolation is imperative. The production liners are being cemented with a life-of-well engineered solution.

The reservoir section consists of two discrete oil-bearing sandstones. Oil recovery will be maximized by water injection from subsea wells. Isolation of the production sands enhance management of the waterflood and thus maximize the producible volume. The challenge was to develop a cement system that could achieve and maintain isolation throughout the life of the field.

A finite element-based analysis tool was used to build a model of the reservoir section. The model was then used to predict the forces on the cement sheath throughout its life under all load conditions, including those caused by pressure and thermal changes during drilling, completion, and sustained production.

The model predicted that a conventional cement sheath could fail in three modes: debonding at the formation, compressive shear, and radial cracking. A cement sheath with lower Young's modulus, higher tensile strength, and shrinkage compensation was required. A series of designs were tested to select the optimum solution that met the life-of-well needs.

The successful implementation of this new approach to cementing required special planning and organization. To date, 13 wells have been cemented with the life-of-well solution, with no operational problems and indication of good placement.

Bond-log results differ from those expected from conventional slurries because of elastic components in the life-of-well slurry. Special data processing techniques have been developed to allow evaluation using conventional bond logs; these are presented in this paper.

Analysis, design, and field implementation discussed in this paper can be applied to field development in other locations where zonal isolation during the well life is critical.
Experimental Study of Oil/Water Flow With Paraffin Precipitation in Subsea Pipelines
Authors: Bordalo Sergio N. , Oliveira Rafael C.
Published: December 2007

The deposition of paraffins was studied in a laboratory simulation of the subsea operational conditions, where the oil pipelines laying on the seabed are subjected to low temperatures. An experimental apparatus was built for a pipe-flow model submerged in a chilling bath of near frozen water. Streamwise pressure and temperature gradients were measured to evaluate the differences in the behavior of paraffin deposition between one-phase oil flow and two-phase oil-water flow. Most works on the behavior of paraffin deposition consider one liquid phase only, while two phases – oil and water – are considered here. Measurements in two-phase oil-water flows show a reduction of the head loss compared to one-phase oil flows, when both are subjected to paraffin precipitation, and photographs show that the layer of paraffin deposits on the pipe wall was significantly reduced in the presence of water.
Impact of Flow Assurance in the Development of a Deepwater Prospect
Authors: Gonzalez Doris L. , Jamaluddin Abul K. M. , Solbakken Trond , Hirasaki George J. , Chapman Walter G.
Published: December 2007

In deepwater production systems, extreme pressure and temperature conditions, multipart sub-sea networks, complex reservoir characteristics, and various fluid phases flowing from the reservoir rock to the surface could promote production interruption due to the formation and deposition of hydrocarbon solids such as asphaltene, wax and hydrates anywhere in the production system. These are flow assurance key risk factors that create significant impact on field development planning, especially, when dealing with marginal deposits having varying fluid characteristics. To reduce the risk, we have adopted a systematic approach to evaluate the potential impact of asphaltene and wax precipitation and deposition.

In this field case, two distinct layers of hydrocarbon deposits are considered marginal from reserves point of view; the upper deposit is a gas condensate layer and the lower is a black oil layer. Because of marginal reserves, mono-bore commingle production was thought to be an option. Also, in-situ gas lifting is considered to be a favorable option. Commingling of live crude oil with a gas stream may lead to precipitation of asphaltenes resulting from changes in composition. Changes in pressure and temperature can also take the system across the boundaries of asphaltene and wax. Being able to predict the formation of solid deposits along the whole production system from downhole to production facilities becomes progressively more important as water depths increase.

This paper describes the impact of flow assurance considerations in a deepwater Gulf of Mexico development project. This study is based on experimental measurements of asphaltene and wax precipitation of a hydrocarbon fluid when contacted with gas condensate from another zone. The evaluation is performed using multiphase thermal-hydraulic behavior in an Integrated Production Model (IPM) that provides system deliverability predictions through the lifetime of the project coupled with asphaltene and wax thermodynamic models. The Perturbed Chain - Statistical Associating Fluid Theory (PC-SAFT) equation-of-state (EOS) model1,2 is the thermodynamic tool used to predict asphaltene precipitation. Wax deposition is predicted using a solid solution model.

The results of experimental and theoretical flow assurance assessment indicated that the black oil has the propensity for asphaltene precipitation caused by pressure depletion during primary production. Simulation results revealed that the downhole commingling with gas condensate is expected to significantly intensify the asphaltene precipitation condition. Results also indicate that wax precipitation will not be an issue during the life of the project.
A Novel Hydraulic Fracturing Model Fully Coupled With Geomechanics and Reservoir Simulator
Authors: Ji Lujun , Settari A. (Tony) , Sullivan R. B.
Published: December 2007

Unconventional fracturing techniques, such as high rate waterfracs, waterflooding or steam stimulation, produced water and cuttings re-injection, CO2 sequestration, N2, CBM stimulation etc., are difficult to model because of strong interactions among the fracturing process, geomechanical changes in the porous media, and reservoir fluid flow. The resulting strong poroelastic/thermoelastic effects, permeability/porosity changes, and possible rock failure (shear fracturing) make current conventional fracturing models inadequate in such circumstances. Therefore, it is necessary to develop new models which include all of these mechanisms and which are capable of integrated data analysis.

This paper presents a new fracturing model with all of these mechanisms included. The model fully couples fracture mechanics with reservoir and geomechanics simulation. This methodology allows us to model fracture initialization and propagation, post-frac multiphase cleanup in the reservoir and fracture, and pre- and post-frac well performance in a changing stress and pressure environment, all within the same system.

The model couples a three-dimensional (3-D) finite element geomechanics model with a conventional 3-D finite difference reservoir flow simulator. The geomechanics module implicitly models fracture propagation via displacements on the fracture face. The flow and geomechanics/fracturing are coupled in an iterative manner that is equivalent to full coupling of geomechanical modeling. The 3-D (planar) fracture geometry and pressure are the common dynamic boundary conditions for the flow and stress modules. The new iterative process yields smooth fracture propagation, and the model has been tested on classical fracturing problems.

A field example where we model a waterfrac stimulation performed in Bossier tight gas sands is presented to demonstrate the models' capabilities as well as the validity and advantages of the approach. The results show that the model is capable of matching a complex history of injections and calibrating the stress-dependency of formation permeability.
Analysis of Production Data From Hydraulically Fractured Horizontal Wells in Tight, Heterogeneous Formations
Authors: Medeiros F. , Kurtoglu B. , Ozkan E. , Kazemi H.
Published: December 2007

This paper discusses the analysis of production data from hydraulically fractured horizontal wells in tight, heterogeneous formations. We consider horizontal wells with longitudinal and transverse hydaraulic fractures, which might be surrounded by a region with natural fractures. These well-reservoir configurations are of interest in many unconventional reservoirs, including tight-gas sands and shale-oil or gas formations. A semi-analytical model that can incorporate the key features of reservoir heterogeneity and the details of hydraulic fracture and wellbore flow is used to compute production decline. Production decline characteristics are presented in terms of transient productivity index. Computation of transient productivity index from field data and the analysis of production decline by transient productivity index are explained. Example applications of production data analysis for fractured horizontal wells in tight, heterogeneous formations are presented.
Gas Production From Class 2 Hydrate Accumulations in the Permafrost
Authors: Moridis George J. , Reagan Matthew T.
Published: December 2007

Gas hydrates are solid crystalline compounds in which gas molecules are lodged within the lattices of ice crystals. Natural hydrates in geological systems are composed mainly of methane. The amounts of hydrocarbon gases trapped in natural hydrate accumulations are enormous, leading to a recent interest in the evaluation of their potential as an energy source. Class 2 hydrate deposits are characterized by a Hydrate-Bearing Layer (HBL) underlain by a saturated zone of mobile water, and are encountered in the permafrost and in deep ocean sediments. The base of the HBL in Class 2 deposits may occur at the edge of, or within, the zone of thermodynamic hydrate stability. Because of the manner of their formation from pre-existing gas reservoirs, permafrost hydrate deposits are generally characterized by high hydrate saturations and are bounded by relatively impermeable strata.

In this numerical study of long-term gas production from permafrost Class 2 deposits, we investigate three different well configurations that involve different production intervals and combinations of depressurization (the main dissociation-inducing mechanism) with localized thermal stimulation. Using high-definition grids and realistic production scenarios, we determine that large volumes of gas can be produced at high rates (several MMSCFD) for long times using conventional technology. The production approach involves initial fluid withdrawal from the water zone underneath the HBL. The production process follows a cyclical pattern, with each cycle composed of two stages: a long stage (months to years) of increasing gas production, and a short stage (days to weeks) that involves destruction of the secondary hydrate (mainly though warm water injection) that evolves during the first stage. A well configuration that initially involves heating of the outer surface of the wellbore and later continuous injection of warm water at low rates appears to yield the highest average rates over the period it takes for the exhaustion the hydrate deposit. We determine that gas production is affected by (a) the intrinsic permeability, (b) the initial hydrate saturation, (c) the fluid withdrawal rate, (d) the thickness of the water zone, and (e) the initial pressure and temperature of the hydrates.
Integrated Flow Modeling Platform Using CAPE-OPEN Standard
Authors: Gainville M. , Roux P. , Pons M. , Pons Michel , Ricordeau A. , Paen D.
Published: December 2007

The design and the operation of petroleum field facilities are facing technical challenges that require numerous and detailed simulations to optimize investments and maximize production. Such calculations rely on a global understanding of production processes that an integrated model from wellbore to topside facilities can supply. To develop such a model, seamless integration of third-party modeling and simulation technologies in a unique software platform is useful and even necessary in many cases.

First, this paper presents the R&D Transient Integrated Networks Analysis (TINA) project that was set up by TOTAL and IFP to address user requirements in term of model coupling, problem solving and data consistency. The TINA's domain of application is design and verification of flowlines from well-bore to topside facilities with a compositional approach. To achieve this objective, the CAPE-OPEN industry standard defined for Computer Aided Process Engineering (CAPE) applications has been used within the INDISS™ platform. The project relies on this platform for integrating modules, on IFP's research knowledge for pipe flow calculations and on third-party software components. TOTAL has brought to the project their knowledge of network design end operational characteristics, as well as the definition of functional requirements of TINA. Validation against field data has also been a profitable input to the project.

Then, this approach is illustrated through several examples integrating three-phase pipe models, valves and surface equipments and also third-party physical and thermodynamic property servers to simulate a deep-water production network.

At last, the paper expresses that the integration of a physical properties calculation server together with advanced pipe models in a software platform dedicated to steady-state and transient simulation enables to simulate deep-water production networks without having to rely on one single simulation solution provider. The interchangeability allows the end-user to choose the most convenient software components for the purpose of a study, and the interoperability allows integrating the latest research improvements together with third-party software components into a global model.
Testing Gas Condensate Wells in Northern Siberia with Multiphase Flowmeters
Authors: Theuveny B. , Zinchenko I. A. , Gazprom Yamburggazdobycha , Shumakov Y.
Published: December 2007

A number of tests were performed in Yamburggasdobycha Gazprom's fields in Northern Siberia area to evaluate the performance of multiphase flowmeters in gas-condensate reservoir applications. The remoteness of the operation and the roughness of winter weather conditions combined with the complexity of the fluid compositions create unique challenges to the successful acquisition of well test data.

The paper discusses the challenges and potential benefits of deployment in line multiphase flowmeters in the difficult operating environment of Northern Siberia.

The reduced logistics and the ability to monitor in real time the true evolution of the gas and condensate wells provide an in-depth view of the actual well performance.

The evolution of the real dynamics of the wells stabilization after a change of choke can be observed and monitored accurately with the in-line Venturi – Dual Energy gamma ray multiphase flowmeter. The importance of the hydrate detection and mitigation processes is essential in the performance of successful tests in the Siberian gas well environment.

The paper details the methodology of the comparison of the well test rates of gas and condensate against traditional means of measurement presently deployed in Siberia. It is based on a rigorous mass balance approach, which enables to consider properly the mass transfer effects when comparing flowrates at different measurements conditions of pressure and temperature.

The presence of hydrates despite the extremely low water content of the effluent is detected by the multiphase flowmeter, which therefore provides also confirmation of the hydrate build up curve.

The challenges to collect representative samples of condensate and gas to ensure proper set-up of the multiphase flowmeter and thus the correct computation of gas and condensate rates are presented, and a number of solutions are described. A discussion of the validity of samples for full reservoir fluid characterization provides insights on the benefits and limitation of sampling in multiphase flow combined with proper conditioning of the samples. The paper further elaborates on the comparison of the fluid composition between traditional surface sampling methods and multiphase testing methods.

The utilization of the dynamic information obtained from the multiphase flowmeter to complement the understanding of the reservoir performance is discussed.
Milling Through an Inoperable Ball Valve at Record Depth Provides for Successful Completion of an Ultradeep Well in the Gulf of Mexico
Authors: Rivas Luis , Powers John L.
Published: December 2007

The Tahiti Field is located in the Green Canyon area of the Gulf of Mexico in water depths in excess of 4000ft. The discovery well was drilled in 2002 in Block 640 and, following appraisal drilling, was subsequently re-entered and successfully tested in 2004. Development of the field followed in 2006 with subsea completions from a drilling vessel but the combination of the water depth, the ultra deep producing zone and the high reservoir pressure presented some major hurdles to the field's exploitation.

Because of the weight of the completion fluid being used (14.8 ppg Zinc Bromide), fluid loss to the formation during completion was a major consideration. To prevent this, a ball-type fluid loss control valve was routinely set in the top frac packer assembly in the production liner, above the producing zone, prior to running the tubing. In January 2007 a well in Green Canyon block 596 was drilled and prepared for completion when the ball valve was damaged which prevented its mechanical actuation process from functioning and put the successful and economic completion of the well in jeopardy. After a review of the alternatives it was decided to perform a milling operation to mill as large a hole as possible through the ball valve and thereby provide access for production. A bottomhole assembly had been designed as a contingency, based on the use of suitable milling technology and a positive displacement motor (a first for this proposed operation), and it was mobilized to the rig, on an urgent basis, along with the required drill pipe work string. The milling job was successfully performed, to drill a 3.800in ID hole through the ball, in a time frame of 2 hours from reaching bottom with the mill, at a considerable savings when compared to other alternatives considered.

In this paper the authors will describe both the completion techniques used and the decision process that resulted in undertaking the milling job. They will go on to describe the procedures and equipment used to achieve its successful completion. Though such a milling job had been performed before, it had never been attempted at anywhere near the record depth of approximately 26,000' and bottomhole pressure in the order of 20,000psi at which the valve was set.
Continuous Improvement in Slop Mud Treatment Technology
Authors: McCosh K. , Kapila M. , Dixit R. , Way P. , Phipps J. S.
Published: December 2007

Oil-based drilling fluids can become contaminated with significant quantities of water as a result of low efficiency well bore displacements to water or brine and from operations such as rig and pit cleaning. The presence of excess emulsifiers and oil-wet solids in typical oil-based drilling fluids allows large quantities of water to be emulsified. These oil-continuous emulsions are often termed slop muds.

This paper presents analytical data on the effects of water contamination on oil-based mud, the resultant slop-mud structure, the influence of shear, and quantification of the critical factors controlling phase-separation and chemical dose. Data will be presented showing the principles of continuous slop-mud treatment both on the laboratory and full-scale defining the important process parameters such as mixing energy, phase recovery rate, recovered drilling fluid properties, and treated water properties.

Development of an understanding of the slop mud stream enabled a novel continuous treatment system to be built which provides efficient and fast phase-separation with recovery of the valuable drilling fluid phase, with significant advantages over current batch-type systems. The process requires in-line injection and mixing of surfactant into the slop mud, then continuous separation of the waste into water and drilling fluid using a gravity separator. The drilling fluid remains as a water-in-oil emulsion containing solids and other chemical additives, which can be reconditioned to acceptable properties for re-use. The water recovery rates are typically 70 to 90 vol% of the total water present in the slop mud. This recovered water is treated using centrifugation, filtration or other water-treatment techniques to meet or exceed discharge consent limits of 15 mg/L total petroleum hydrocarbon. Water collected in the rig deck-drain system which may also be contaminated with oil or oil-based mud can also be treated in the same manner as the recovered slop water.

Because the process allows continuous treatment of the slop mud stream, the resultant equipment has significant benefits over the current batch-type systems including higher throughput and decreased footprint.
Formate Fluids and Environmental Regulations: A Global View of Benefits and Challenges
Authors: Gilbert Y. , Pessala P. , Vaahtera A. , Raivio T.
Published: December 2007

This study compares locational differences in regional and national environmental regulatory approaches to offshore environmental protection in relation to chemicals. Environmental regulations set acceptable discharge limits and define management boundaries for all related actions, from setting strategic HSE policy targets to choosing chemicals for specific operations. The local variations in regulations mean that chemicals acceptable in one location may not pass environmental consent conditions in another. Challenges such variability represents to multinational offshore operators wishing to harmonise chemical risk assessment and identify chemical Best Available Technology (BAT) on a global basis are identified and discussed.

Formate fluids are used as an example throughout the discussion. These chemicals are illustrative of some inconsistencies between legal regimes. They demonstrate a low level of toxicity and have positive environmental performance profiles, as illustrated through the use of several case studies. Yet formates cannot be used or discharged in all offshore areas in the same way.

Certain regulatory variations can be traced to how ecotoxicological data is utilised within the environmental consent process. Reliance on single test data for setting absolute thresholds may lead to very different consent conditions than combining results from several tests - which together mimic a simple food chain - and applying this as input to risk modelling. For the case study chemicals, the detailed risk assessment approach indicates a positive environmental profile, favourable for discharge consents. In contrast, the single test threshold approach leads to total containment requirements. In the face of such challenges, unified corporate risk assessment criteria can support informed decision making and give operators the benefit of consistent identification of chemicals representing BAT.
Second-Stage Challenge for the PRODML Standard: Adaptive Production Optimization
Authors: Weltevrede Ben , Doniger Alan , Ormerod Laurence , DeVries Stan
Published: December 2007

PRODuction xML (PRODML™) was started jointly by BP, Chevron, ExxonMobil, Shell, and Statoil in early 2005 as a data exchange mechanism to support production optimization within a ‘digital oil field’ context. These companies have been joined by Aspentech, ConocoPhillips, Euriware, Halliburton, InfoSys, Invensys, Kongsberg Intellifield, Matrikon, OSISoft, P2ES, Pioneer, Petroleum Experts, Schlumberger, TietoEnator, and Weatherford. Energistics® has stewardship of PRODML and fosters further development.

There is significant industry interest in implementing digital oil field strategies. Corporate and government initiatives anticipate significant, sustained improvements in recovery and operating efficiencies while maintaining safe operations. This will require robust, trustworthy, implementation of measurement, optimization and automation technologies.

Version 1.0 of the PRODML standard, released in 2006, enables a range of production optimization use cases to handle an information hierarchy which includes time series data. This lays a foundation for adaptive optimization involving interaction between applications and data stores from multiple vendors. Such optimization is important both for situations with low-frequency changes, such as waterfloods, and for those requiring agility, such as compliance with pipeline, liquefied natural gas, and power-generation customer-export schedules that may cycle within a day.

PRODML V1.0 provides a means of transferring data between applications incorporated in simple, common use cases. However, it did not address the task of accommodating changes to the physical configuration of the network, such as the addition of a well or a sensor, without having to manually reconfigure applications. Such changes are commonplace.

In 2007, the PRODML work group focused on managing changes in production network configuration and in the capabilities of system components. The result enables optimization and reporting architectures and data management processes to adapt to changes faster with less effort and fewer errors. PRODML has therefore become a tool which can be used in implementing robust, trustworthy optimization and automation processes.

Several example use-cases are included to illustrate how PRODML can be applied.
New Level of Expandable Connector Qualification Helps Minimize Operational Risk in Solid Expandable Liners
Authors: Ring Lev , Deltombe Philippe , York Patrick , Baker Robert V.
Published: December 2007

Expandable connectors continue to be the Achilles Heal of solid expandables due to the simple nature that the connectors need to sustain their tensile, compressional and sealing integrity, before, during and after expansion. Solid expandable products such as monobore liners and monobore clads, which push expansion ratio requirements to 20% and toward 30%, require connectors with qualification needs that exceed earlier product applications.

The API and ISO qualification bodies are now addressing the need for standardization recommendation procedures for the testing and performance specifications of solid expandable system tubulars and their connecting devices.

Connector failures and inconsistent reporting methods of specifications of solid expandable systems' performance envelops have driven the industry to attempt to apply standard methods of API connector qualification. Even applying conventional testing and qualification methodology for expandable connectors cut on seamless tubulars fell short of thoroughly qualifying these connectors for use in the extreme environment of cold working connected tubulars in situ.

Therefore, a conventional, four-quadrant service load performance envelop has been adapted and developed for the new requirements. Even expansion in "fixed-fixed" conditions has been added to help ensure consistent performance in downhole service. This type of connector qualification has historically rarely been conducted, and then only on a very small range of the possible expansion ratio or for only one size and type of connector.

This paper describes the need, the methodology and the processes required to qualify connectors to this level. This extensive testing and qualification process has yielded connector performance ratings that can be verified with empirical data for every size and style connector for carbon steel as well as CRA tubular materials.

With solid expandable products being used in a wider and broader arena of applications with associated high risk and expensive consequences, it is critical to qualify each size and type of expandable connectors, clearly document these qualifications with both theoretical modeling and empirical data and be prepared to provide the end user with sufficient proof of the expandable connector's performance ratings.

This paper explains how this new methodology provides this level of proof of performance to the end users.
Updating the Geomechanical Model and Calibrating Pore Pressure From 3D Seismic Using Data From the Gnu–1 Well, Dampier Sub-Basin, Australia
Authors: White Adrian , McIntyre Brett , Castillo David , Trotta Julie , Magee Marian , Ward Chris , O'Shea Paul
Published: December 2007

A postmortem analysis of the Gnu–1 well was conducted to help understand the drilling experiences in the context of the pore pressure and stress profiles. The postmortem involved a review of the drilling experiences, the analysis of CAST image data, wireline log data and the LWD logs. This information was used to refine and verify a geomechanical model (in-situ stress, pore pressure and rock mechanical properties) in the vicinity of the Gnu–1 well. Of prime concern was the verification of the pre-drill pore pressure prediction previously undertaken using 3D seismic velocity data and offset well data. Wellbore failure and natural fracture analysis were an integral part of the postmortem. Wellbore breakouts seen in the image data allowed the pore pressure in the 8½" hole section of Gnu–1 to be constrained. Modelling using image data collected in the Athol Formation indicates that the pore pressure does not increase as rapidly as was estimated in the pre-drill study. Pore pressures in the North Rankin Formation and below were consistent with the pre-drill study. The geomechanical model was able to explain the losses seen in the Athol Formation in Gnu–1 when using the mud weights experienced by the open hole at the time of drilling.
Unlocking the Potential of Mature Fields – An Innovative Filtering and Analysis Approach to Identify Sidetracking Candidates in Mature Water Flooded Fields
Authors: von Pattay Patrick W. , Hamer Jeff , Strasser Ralf
Published: December 2007

This paper presents an innovative filtering and analysis approach to identify candidates for sidetracking in mature water flooded fields. It targets bypassed reserves to improve production and ultimate recovery from such fields at once. The method is based on production engineering concepts, it is very time efficient and requires only a minimum of data, which makes it in most cases more suitable than other methods.

The approach provides a filtering concept to select all wells that might have bypassed reserves in their drainage area and provides a step by step analysis to verify, quantify, and locate these bypassed reserves. Further it provides a comprehensive method to develop a production forecast for a potential sidetrack. It also presents a set of criteria to select the most suitable well to sidetrack. Finally it allows leveraging all associated uncertainties by linking the economic analysis to a Monte Carlo simulation, which is critical for a sound management decision.

Whereby, the approach tackles the four most critical factors, how much data are needed, how much resources are required, how long will it take to come to a decision, and what will be the certainty of the output.

Recapitulating, the approach presented here allows selecting candidates for sidetracking in mature water flooded fields based on a minimum of data time efficiently, which allows making the right management decision to unlock some of the potential of these kind of fields at attractive ROI and NPV.
Concise Testing Guidelines for Crosslinked Fluids Saves Time and Money
Authors: Core Jerrod A.
Published: December 2007

Successful fracture treatments that utilize crosslinked fluids are dependent on the fluid maintaining viscosity at down-hole conditions. Pre-job testing of the crosslinked fluids is a critical step in knowing how the fluid will perform during the treatment. Using proper testing guidelines and contingencies in place, the service company can provide operators useable, predictable fracturing fluid test data. Without such guidelines, extraneous testing, unusable data, and job delays can result.

Crosslinked fracturing fluids are tested using a rotational viscometer designed for testing at elevated temperatures and pressures under a constant shear environment. Such viscometers are among the most economical and readily available approximations to the down-hole environment experienced by fracturing fluids. By setting the rotational viscometer to approximated job conditions, and utilizing treatment-specific water and chemicals, it is possible to produce data that predicts the rheological properties a crosslinked fluid will exhibit during fracture treatment.

Before rheological testing begins, the operator and service company must agree upon parameters that are acceptable for the testing procedure. While the ISO-13503-1 document outlines standard practices for measuring the viscous properties of completion fluids, there are job-specific factors that are not addressed in this document. First, the operator may want to specify the exact rheological requirements expected in order to categorize fluid as effective for the treatment. Next, the temperature and shear rate settings must be agreed upon to ensure the viscometer is run at the most probable down-hole conditions for the given job. Finally, the operator or service company may pre-determine the range of chemical additive loadings for several of the crosslinked fluid components (i.e., an optimization path). This paper will outline areas the of a crosslinked fluid test that need to be clearly defined prior to testing, and will show the potential time and financial costs associated with the lack of concise guidelines.
Geochemical Evaluation of Depositional Environment of Parh Limestone, Southern Pab Range, Balochistan, Pakistan
Authors: Naseem Sadaf , Naseem Shahid , Sheikh Shamin Ahmed
Published: December 2007

Geochemical studies of Parh Limestone, through major and trace element analyses, were made to evaluate its depositional environment. Parh Limestone represents Upper Cretaceous period in the Kirthar and Sulaiman provinces of Lower Indus Basin. The Parh Limestone of Turonain-Santonian age is well exposed in NNW-SSE trending Pab Range of Balochistan, which merges into Kirthar Fold Belt northwards. The Indian Plate motion, sea-level fluctuations and volcanism were the main controlling factors responsible for the distribution of elements during the deposition of Parh Limestone. During the cycle of deposition of Parh Limestone the distribution of Mn and terrigenous material (clay) revealed High Stand System at the beginning (Turonian, 91m.y.), which latter turned into Low Stand System and finally terminated as Transgressive System with a very broad shelf environment (Maximum Flooding Surface). The Al/Mn+Fe+Al ratio of the Parh Limestone revealed slow rate of drifting initially and high rate at latter stages due to high rate of sea-floor spreading. The Ca/Mg, Ca/Fe, Mg/Fe ratios suggested hemipelagic environment of deposition. The contents of Ba, Zn and Co were higher than the average abundance in the limestone reflecting partial influence of igneous activity at the time of deposition. The composition of an igneous sill, at the base of Parh Limestone demonstrates ocean-floor tholeiites, affiliated with Mid Oceanic Ridge Basalts (MORB).
Controlling Gas Channeling Problem Within and Near Vicinity of a Gas Well: Case Study Bagla Gas Field
Authors: Ahmed Shakeel , Majeed Arshad , Ahmed Bashir , Aftab Farrukh
Published: December 2007

Integrity of well structure is a vital factor to produce hydrocarbons from subsurface. It is important that well structure along with cement behind the casings remains intact to get controlled and risk free production during life of a well. This objective is achieved by making every effort to ensure good cement behind pipe and selecting suitable well tubulars honoring reservoir fluid composition and fluid flow rates. In case the criteria of well integrity is not met, flow of fluids behind casing and communication between tubulars create problems and may lead to uncontrolled flow of well fluid creating environmental and safety hazards.

Bagla gas field is located within the Indus Basin with producing horizon in Lower Goru Formation of Cretaceous age. This is a single well field, which was drilled by Phillips Petroleum Exploration Ltd during 1988. Later on OGDCL acquired this field. The field could not be developed due to its marginal reserves, remote location, non-availability of gas buyer in near vicinity of the field and non-attractive economics in case gas is sold to SSGCL due to high cost of pipeline quality gas to SSGCL gas transmission network.

During April 2004 gas channeling to surface was observed in the nearby area located within a radius of 2-3 km from the Bagla well. This gas channeling was causing environmental and safety hazards in the area. This paper discusses the measures taken by OGDCL to diagnose the cause of problem and efforts made to control the well to contain the environmental and safety hazards in the area.
Drill Automation for the Space Environment: Lessons Learned
Authors: Zacny K. , Paulsen G. , Cooper G.
Published: December 2007

This paper examines drilling autonomy in the context of space exploration and how it might differ from autonomy required in an oil well drilling.

The main driver in the planetary drill automation is a large communication delay (i.e. the drill can not be remotely controlled) whereas in the petroleum well drilling it is reduction in manpower as well as it serves to remove human operators from a dangerous location where heavy equipment is operated 24 hours a day regardless of the weather conditions. Both planetary and petroleum drills share common problems such as data ambiguity (the same data can come from two different events) as well as a large number of data inputs that need to be processed and analyzed in real time for automation to be effective.

The petroleum industry is profit driven; thus reliability of various mechanical components is carefully optimized since higher reliability means also higher cost. In the space industry, the reliability of all systems and especially those that form a single point failure must be very high. This requires a lot of testing and makes space exploration very expensive.

Since automation is inherently expensive, a careful analysis needs to be performed in order to determine which operations may be optimized and which should not. This is because some operations are still done better and cheaper with humans.
Compositional Modeling of Two-Phase (Gas/Water) Flow in Gathering and Transmission Pipeline Systems
Authors: Zaghloul Jose , Adewumi M. A. , Ityokumbul M. T.
Published: December 2007

The current work presents a fully-compositional tool for modeling systems exhibiting two-phase (gas-water) flow. The tool couples complex hydrodynamic and thermodynamic models to describe the behavior of fluids flowing in a pipe.

Results show that the model is capable of predicting water condensation in the pipe, estimating pressure/temperature profiles, and handling different flow patterns and their transitions. Moreover, the model has the capacity of estimating the concentration of hydrocarbons, carbon dioxide, hydrogen sulfide, methanol, and other substances dissolved in the aqueous phase.

Hydrate formation is related to the presence of methane, ethane, propane, butanes and nitrogen in a gas stream, while acid is expected to form when significant amounts of CO2 or H2S are present in the aqueous phase. The model developed in this study provides production engineers with an excellent tool for evaluating the potential formation of hydrates and/or acids in piping systems.

Several cases were used to validate the model. Model predictions were compared against experimental data obtained by Eaton et al. (1967). The flow patterns and pressure profiles calculated by the model accurately matches experimental data. The pressure profile calculated is within 2.0% of the reported experimental values. Similarly, the average liquid holdup estimated was in good agreement with the values reported by Eaton et al. (1967).

The model is capable of predicting the initial water condensation point in the pipeline and the concentration of different substances in the aqueous mixture. The tool gives production engineers important information on how much hydrate/corrosion inhibitors to inject and where, thus saving in the design, operation and maintenance of pipeline systems.
Crude Oils of Kentucky and Tennessee: Characteristics, Problems, and Solutions
Authors: Barker K. M. , Breitigam J. V. , Brotherton R. L. , Goff L. L. , Hake K. J. , Schofield R. D.
Published: December 2007

Paraffin and asphaltenes can cause many types of problems depending upon the characteristics that they give to a particular crude oil. The problems can range from deposition of paraffin or asphaltenes in the formation or equipment, causing the oil to congeal, oil wetting of the formation, causing emulsions or rigid film emulsions during acid treatments. The analysis of crude oils from wells in Kentucky and Tennessee has been carried out to determine the possible organic problems that will affect the production from these wells. Problems, causes, and solutions will be discussed with case histories presented.
Is Bati Raman Heavy Oil Field a Triple Porosity System?
Authors: Arslan Izzet , Akin Serhat , Karakeçe Yildiz , Korucu Özlem
Published: December 2007

This paper presents a seamlessly integrated naturally fractured reservoir (NFR) modeling process for the ongoing Bati Raman heavy oil field rejuvenation project. As a part of the project, remedy of ongoing immiscible CO2 injection and successfully achievement of a near term steam flooding pilot test depend on understanding the heterogeneous natural fracture system. The naturally fractured rock and vug characteristics of the reefal/subreefal carbonate reservoir, and lateral and vertical facies distributions have been a challenge for establishing a successful 3D conformance process.

An improved static model was constructed using the results of 2D and 3D seismic, sedimentological model and systematic fracture characterization. The new 3D seismic survey helped to identify the fracture regions, and had direct input to the new reservoir model with new structural information as well as fracture attributes. Fracture density and apertures of rare large true fractures were observed in the reservoir both on cores using a drill-core imaging system, and in FMI log findings. FMI logs provided the textures of vugs as well, ranging from less than 1 mm to 5 cm in size. The vuggy porous medium was handled in two ways: the interconnected vugs added into the fracture system since they build major pathways in the fractures between injector-producer pairs, while the isolated vugs are a part of the matrix system adjusted for compressibility. Matrix and fracture properties were distributed using sequential Gaussian simulation (SGS) and neural network algorithm constrained to the conventional log profiles within a 3D structural framework. This was followed by a calibration of well tests and CO2 breakthrough patterns, and hydrocarbon volume uncertainty assessment. The methodology optimizes a multi-disciplined integration and interpretation workflow for an unconventional multi-porosity complex model that is required in the distribution of flow properties such as saturation and pressure.
Shapes of Flood Fronts in Heterogeneous Reservoirs and Oil Recovery Strategies
Authors: Montaron Bernard A. , Bradley David , Cooke Anthony , Prouvost Laurent , Raffn Anne Gerd , Vidal Alain , Wilt Michael
Published: December 2007

The limited grid resolution used for dynamic reservoir simulations has contributed to convey the perception that fluid flood fronts have fairly smooth shapes. However it has been known for a long time that reservoir permeability heterogeneities create fractal-like fluid front surfaces. Many sandstone reservoirs and most carbonate reservoirs are known to be highly heterogeneous. Fractures, texture, depositional facies, diagenesis are well known causes of heterogeneity in carbonates. In this paper we present new results of computer simulations at high grid resolution of water flood fronts in reservoirs with heterogeneous wettability distributions. Wettability is an important factor in carbonate reservoirs and these simulations clearly show the critical impact of heterogeneous wettability distributions on sweep efficiency and recovery factors. Also discussed are results for reservoirs combining heterogeneities of various origins such as matrix permeability, wettability and large scale heterogeneities such as fracture corridors. The geometry of fluid fronts predicted by these simulations is compared with actual fluid fronts monitored using advanced processing technology of high resolution 4D seismic. We also review how saturation profiles in swept zones can be estimated using well-to-well electro-magnetic image cross-sections. Finally, the impact of complex front shapes on sweep efficiencies, recovery factors, water breakthrough predictions and water cut curves versus time is discussed. Examples of possible production scenarios using intelligent completions and fluid front monitoring techniques to maximize recovery in spite of reservoir heterogeneities are presented.