bluuebunny/crossref_metadata_2025 huggingface dataset:
An Investigation of Gas Well Testing Under Constant-Bottomhole Pressure Conditions, High-Velocity Flow Effects, and Formation Damage
Authors: Nashawi Ibrahim Sami , Qasem Fuad H. , Gharbi Ridha B. , Mir Mohammad I.
Published: December 2007

This paper presents an investigation of the validity of applying the constant-pressure liquid solution to transient rate-decline analysis of gas wells. Pseudo-pressure, non-Darcy flow effects, and formation damage are incorporated in the liquid solution to simulate actual real gas flow in the vicinity of the wellbore. The study shows that for constant-bottomhole pressure gas production the conventional semilog plot of the inverse of the dimensionless rate versus the dimensionless time used for liquid solution has to be modified to consider the high-velocity flow effects. This is especially true when the reservoir permeability is higher than 1 md and the well test is affected by non-Darcy flow and formation damage.

This paper also presents a novel systematic method to determine the formation permeability, mechanical skin factor, and non-Darcy flow coefficient from a single constant-pressure production test. The working equations are written in such a way that allows a graphical analysis of the variable rate with time that is analogous to the analysis of constant-rate production test. The analysis procedure is simple and straightforward. It does not require type-curve matching or correlations. The applicability of the proposed method is illustrated using several simulated examples. The input formation permeability varies from a low value of 0.1 md to a high value of 5 md. The ratio of the downhole pressure to the initial reservoir pressure ranges from 0.1 to 0.8.
A New Approach for Estimating Well Productivity and Reservoir Pressure Using Surface Performance Data
Authors: Al Qahtani Abdullah M.
Published: December 2007

Well productivity index is an important factor by which well performance is gauged with itself or as oppose to other wells. The change in the well's productivity is quantified by monitoring the changes in its productivity index. Another factor that is equally important and of mutual reaction with the well's performance is the reservoir pressure. This issue is complicated with the changes taking place in both parameters.

Conventional methods of determining well productivity and reservoir pressure involve transient testing which helps petroleum engineers diagnose well and reservoir performances and make affective well producing and reservoir management strategies. Viewed as such, it is important to run transient test in new wells or wells experiencing a drop in their productivity due to formation damage. The data during a transient test are acquired by placing a pressure gauge downhole to capture the reservoir response due to the changes in well flow. However, due to the logistics involved, it is difficult to do frequent transient testing especially for offshore wells. Transient tests are also costly and interrupt delivery of hydrocarbons. For these reasons, such tests are run less than what operators would require to help evaluate well/reservoir performances.

This paper presents a new approach that is based on a mathematical model that uses surface performance data to determine the reservoir and well productivity index. This approach captures the reservoir response as a result of changing the flowing wellhead pressures and flow rates by having a variable rate tests that are presented by surface wellhead pressure and corresponding flow rates. From the established trend, regression analysis is used to obtain a fit and estimate those parameters.

This approach will enable faster evaluation of well and reservoir performances, elimination of cost of wireline crews and equipment, test of wells with restricted tubing or obstruction in tubing, and conducting frequent testing on wells experiencing a drop in their productivity due to formation damage. The application of this approach in the field revealed that the results obtained using this technique compare very favorably to that measured by transient testing.
Reservoir Description and Static Model build in Heterogeneous Mauddud Carbonates: Raudhatain Field, North Kuwait
Authors: Azim Shaikh Abdul , Al-Ajmi Hussain , Rice Craig , Bond Deryck , Abdullah Shehab , Laughlin Bruce
Published: December 2007

The Early Aptian carbonates of the Mauddud Formation form giant hydrocarbon reservoirs in North Kuwait. Reservoir description and distribution of rock properties in 3D space are challenging due to inherent reservoir heterogeneity. A robust depositional model driven by sequence stratigraphy, petrophysics tuned to dynamic data and innovative static modeling techniques were used to characterize this complex reservoir.

The Mauddud carbonate sedimentation took place in a low angle ramp setting. The basal part of Mauddud consists of shales and low energy carbonates deposited in a transgressive systems tract. The main reservoir was deposited during the subsequent highstand systems tract. High-energy inner ramp grainstones preserve the best primary porosity and permeability. Reservoir quality deteriorates in mid ramp to inner ramp wackestones and mudstones.

Diagenetic carbonate concretions destroy porosity and permeability. It is more pronounced in mud-rich packstone / wackestone fabrics. Early hydrocarbon emplacement has terminated concretion growth in crestal areas of the field whereas concretion formation and subsequent reservoir degradation continued in the water leg through late diagenetic stages. Rudistic floatstones, radially fractured concretions and small-scale fractures in low-porosity brittle rocks are the main thief zones in the reservoir.

Through the integration of core, openhole logs, production logs, and pressure transient analysis, a deterministic permeability model has been developed that characterizes the reservoir. Logs have been reprocessed to identify zones of secondary porosity (enhanced permeability) and fracture– prone zones. Porosity-Permeability transforms for matrix properties and fracture-prone intervals were developed. This methodology results in log-derived permeability profiles that match production log profiles and well test Kh estimates.

A fine Geological model with 85 layers and 2.5 million cells has been built to capture the primary depositional units. The horizons bounding the flow units are major flooding surfaces. The lithofacies associations have been modeled as composite objects restricted to facies belts. As porosity was observed to be decreasing towards the flank, trend modeling has been used to model the effective porosity. Another geological model with 166 layers was built to capture the small-scale heterogeneity caused by vuggy zones and fractures. The vugs and fractures have been modeled as objects restricted within an area demarcated by poorer seismic coherence. The Matrix permeability was enhanced by vuggy permeability and fracture permeability.

The paper describes the challenges in reservoir description and static modeling of this complex reservoir in detail.
Creative Modeling of a Heterogeneous Carbonate Reservoir in Bahrain Field (Kharaib Reservoir)
Authors: Qassim Naji A. , Waleed A. Jawad , Abdulwahab Ayda E.
Published: December 2007

This paper describes a case study of creatively utilizing open-hole logs and defining rock type and geostatistical permeability versions. The paper then briefly describes the process of up scaling and simulation that followed. Defining the rock types is the first step in reservoir characterization and modeling. Three rock types were defined for Kharaib reservoir; each rock type has a characteristic porosity and permeability relationship. Stratigraphic layers were utilized to QC the rock types distribution. The simulation of porosity and permeability constrained by the rock type model for the entire reservoir. Care was taken during the rock type simulation, because the resulting model will guide the porosity and permeability simulations. Standard Sequential Simulation was used to produce the models. A modified version of the SIS algorithm is needed to ensure that final images honor the local means and spatial trends of different categories. Careful design of the simulation model, aerial grids, fine reservoir layering, quality control and up-scaling process are vital to retaining the static models main heterogeneity features of carbonate reservoir. The model was then fit into dynamic simulation for history matching and validation.
Repair Intervention of Worn Production Casing in the Sajaa Field
Authors: Pattillo P. D. , Pruitt R. D. , Al Nakbi A. I. , Gent J. L. , Young K. , Zhang X.
Published: December 2007

The Sajaa gas/condensate field is located onshore in the Emirate of Sharjah UAE. Production is from the Thamama limestone reservoir at 11-13,000 ft. TVD. Reservoir pressure depletion is creating an ever increasing collapse pressure differential on casing opposite overlying sediments.

Sajaa field has a history of collapsed casing on wells Sajaa 33 and 39, with two collapse events in the latter wellbore. The current study summarizes the theoretical effort to prevent collapse in the remaining Sajaa wells. A companion paper1 discusses the related live well workover program.

Current Sajaa completions are packerless, producing up the tubing or up the annulus between the production casing and a capillary string for corrosion inhibition. Coincidentally, the collapse resistance of the production casing is reduced by severe wear associated with the use of tungsten carbide hard banding while drilling the reservoir sections of the wellbore.

Setting the context for the study, the well(s) tubular program, pore and internal pressures, and design safety factors are presented. This introductory portion also clarifies the differential collapse load to which the tubulars are subjected.

Loss of collapse resistance due to severe wear is then addressed. The theory of wear prediction is reviewed, and then demonstrated, as the drilling parameters of several of the affected wells are used to predict their current state. These predictions are then compared to mechanical caliper measurements taken during intervention and repair. Further, using specially machined wear grooves, the effect of wear on collapse of a casing cross section is experimentally validated by full scale collapse tests.

Results of both the wear prediction/measurement and its effect of collapse resistance are input to a probabilistic decision tree to tailor each well's workover strategy. The decision tree permits risk-weighting of alternate strategies for repairing the Sajaa casing. An important component of the decision tree is the consideration for time varying alteration of the collapse differential pressure with reservoir depletion.
Rosetta Field Development - Designer Water Based Drill-In Fluid Ensures Gravel Pack Completion Success
Authors: El Raheem Taher Abd , Toubar El Metwalli , Gamal Medhat
Published: December 2007

The use of a custom-designed water-based drill-in fluid, to minimisereservoir damage and facilitate successful open hole gravel pack completions,was vital to ensure a successful operation and maximise gas production inRashpetco's Rosetta field offshore Egypt, due to the nature of the producingsand.

Prior to drilling and completion operations, extensive laboratory work wasconducted including core flood return permeability and formation/fluidcompatibility studies in addition to gravel and screen studies. The drill-influid formulation and particle size distribution was optimised to ensure athin, impermeable filter cake and minimal filtrate invasion.

The low-solids saturated salt/potassium chloride drill-in fluid systemhelped stabilise inter-bedded shales while drilling the reservoir section. Nolosses of completion brine were experienced during the gravel packingoperations and gas production flow rates on all the wells drilled in theRosetta field exceeded expectations without requiring any stimulation.

Based on this proven success, the same technique will be implemented onRashpetco's West Delta Deep Marine (Scarab/Saffron deepwater developmentcampaign) to minimise the reservoir damage and maximise production.
Water Flood Conformance in a Highly Faulted Carbonate Reservoir
Authors: Shiflett David , Simlote Vishnu , Burns Scott , Thompson Tommy
Published: December 2007

ISND Shuaiba is a lower Cretacious carbonate reservoir off shore of Qatar. (Figure 1) It is a low permeability, high porosity wackestone-packstone with vertical permeability barriers. Aquifer water drive is weak and reservoir pressure is slightly above bubble point. Primary recovery is low. Waterflooding is required for increased recovery. Two systems of faults/fractures at oblique angles to one another cross the reservoir and divide it into a system of semi autonomous reservoir blocks. One system of fractures is conductive to fluids. The other system of fractures constitutes a set of no flow boundaries. The reservoir compartments are mapped with a seismically driven fault model built by integrating fracture image data and drilling, lost circulation experience. The predictive and explanatory model of fracture orientation and behavior is consistent with the regional stress evaluation. An injection plan is designed to repressure the reservoir compartments and optimize EOR reserves. The strategy is to place a vertical point injector at an optimal point in each reservoir block and access multiple reservoir blocks with horizontal producing wells. Cost effective vertical point injection is achieved by employing a single horizontal injection well with multiple vertical injection laterals
Business Process Re-Engineering in the Upstream Sector of E&P Companies. A study of Staff Perceptions and Critical Success Factors
Authors: Elie Daher
Published: December 2007

This paper investigates the perceptions of staff with regard to critical success factors (CSFs) for successful Business Process Re-engineering (BPR) for the upstream sector of the Exploration and Production (E&P) companies. The conclusion and recommendations were drawn after a detailed review of literature discussing BPR implementations in various industries and using the results of a study performed on a specific implementation of a BPR project for Information Management in a mid-size E&P company.

This paper shows that the factors deemed most important for successful BPR included items such as top management support, commitment and understanding of BPR, communication, empowerment and alleviation of downsizing fears. Some unique characteristics for the E&P sector have particular bearing on the application of BPR. They include the existence of many intricate overlapping processes with multiple stakeholders, changes in policy direction or in Oil prices, the existence of a professional workforce and the existence of defined internal organizational boundaries. Suggestions on how to maximize the chances of success in the BPR are discussed.
Using Knowledge Mapping Techniques to Build a Living Full-Field Model of an Oil Field
Authors: Al-Rasheedi Hussain , Chapman Terrance V. , Oskay Mehmet , Al-Khamees Waleed
Published: December 2007

The objective of this paper is to share the knowledge mapping techniques and experiences of those involved in this activity.

The purpose of a knowledge map is to show people in the organization where to go when they need expertise or have expertise to share. A knowledge map is a picture of what exists in the company as well as where it is located. It therefore can be used as a tool to discover opportunities to be exploited and gaps to be filled. When the same reservoir has different production policies for different portions of the field, Planners from all teams suffer from incomplete data. Information is shared when available, as in the case of the full-field reservoir model. But this is not thought to be optimal, when other reservoir studies have been conducted in isolation and expertise is not shared. A more coordinated approach is required that would continuously bring together all the available knowledge and make it always freely available to analysts and decision makers.
Field-Testing a Compact Multiphase Flow Meter - Offshore Saudi Arabia
Authors: Warren P. B. , Al-Dusari K. H. , Zabihi M. , Al-Abduljabbar J. M.
Published: December 2007

An automated and compact multiphase flow meter (MPFM) tested offshore Saudi Arabia has accurately measured three-phase flow rates under existing field operating flow conditions. A three-month field test was conducted utilizing over 160 well tests under varying operating conditions. A meter was installed on an offshore test barge, so that individual wells could be tested in series with traditional test separator methods. For these trial tests, the total liquid rate ranged from about 335 to 12, 333 barrels per day, the GOR ranged from about 67-185 SCF/STB and the water cut ranged from 0 to 70%. The results show that over 93% of the well tests were within +/- 10% of test barge results for all liquid, oil and water cut measurements. While gas measurements were determined to be within +/- 15% in 63% of the wells tests. Also, the results for the gas measurement comparison are discussed although the gas measurements were evaluated against historical field PVT data, due to the unavailability of a valid test barge gas rate comparison meter.

The project platforms currently identified for multiphase metering differ in physical size and vary from single well to 8 well configurations. For accurate reservoir management, each well is individually rate tested to monitor well performance and to provide data for field allocation and planning purposes. The wells are presently being evaluated by test barges, which are equipped with testing facilities. A multi-phase flow meter was successfully field-tested as an alternative to the use of the test barges. Permanent multiphase flow meter installations will provide more frequent tests and considerable economical savings in the long run.
Computer Simulation of Air Pollution in Dalan Refinery
Authors: Feridun Esmaeilzadeh , Jadidi Ali Reza
Published: December 2007

Dalan Refinery is located in Farashband area at 200 km far from southwest of Shiraz city. Pollutant components from the dehydration units in Dalan refinery cause to pollute the surrounding environment. The main pollutant components are aromatic hydrocarbons such as benzene, toluene, ethyl benzene, propyl benzene, TEG and hydrogen sulfide. In this project firstly the refinery is simulated by PROII software. Then Gaussian Plume model has been used with plan data for obtaining the concentration gradient of pollutant components. The effects of different variables upon the performance of pollution have also been studied. These variables include wind velocity, dispersion coefficient, cloud cover, radiation, stack height and exit temperature of pollutant-component stream.

In this study using stack in comparison to cooling or burning of the pollutant components is economically cheaper and for health safety is also suitable.
Asphaltene Precipitation in High Gas-Oil Ratio Wells
Authors: Kokal Sunil , Al-Ghamdi Abdullah , Krinis Dimitrios
Published: December 2007

Asphaltene deposits have been observed in a number of high gas-oil ratio (GOR) wells in north Ghawar. Even though the oil reservoir is undersaturated two small gas-caps are present as a result of gas injection during the 1960s and 1970s. New development wells drilled recently to produce oil and gas from the gas-cap areas have experienced asphaltene deposition. The cause of precipitation is the stripping of the asphaltenes from the crude by the gas.

This paper describes the results of an investigative study that was initiated to determine the precipitation mechanism and ways to alleviate the deposition problem. Asphaltene precipitation experiments were conducted at reservoir conditions in a special PVT apparatus. The effect of gas-oil ratio on asphaltene precipitation was determined by titrating the reservoir oil with gas-cap gas. Bulk deposition tests were also performed at different GORs with reservoir fluids. The results demonstrate that the onset of asphaltene precipitation occurs at relatively low GOR values. However, the amount of asphaltene precipitated at the onset is negligible. Asphaltene precipitation and deposition increase with increasing GORs. Asphaltene deposition envelopes are provided for the reservoir oil as a function of pressure and temperature. Guidelines are provided to alleviate the problem by controlling the GORs. Recipes for solvent treatment including asphaltene dispersants are also described in the paper.
Production Improvement by Downhole Demulsification - A Simple and Cost Effective Approach
Authors: Dutta Bapan K. , Ahmed Hani H.
Published: December 2007

Downhole demulsification of crude oil increases well production and profitability by reducing vertical flow pressure loss. This paper presents a practical, field-tested method to accomplish downhole demulsification without the mechanical complexities of the conventional downhole injection system. Chemical is injected at surface with a pneumatic dosing pump into the gas lift stream. Lift gas entering into the tubing-casing annulus carries the chemical downhole to the injection point deep into the tubing and blends it with the well fluid to prevent emulsification. Production improves after a few days of chemical injection as the downhole demulsification process stabilizes. Successive trials have proved the effectiveness of the approach in terms of improved production. In view of the simplicity and cost effectiveness of the method, it has also been applied in naturally flowing wells that produce below their potential because of emulsion. Case study and result of such trial have been discussed in the paper that shows promising success. It has broadened the application scope of the system to emulsion-infested natural flow wells.
Characterization of Asphaltene Precipitation Effect on Reducing Carbonate Rock Permeability
Authors: Kocabas I.
Published: December 2007

Asphaltene precipitation is a nearby wellbore phenomenon with strong adverse effects in rock permeability affecting the production operations. However, a complete characterization of the asphaltene precipitation effect, namely quantifying the degree, scale and mechanisms of permeability reduction still remains to be resolved. In this paper we report the results of a series experiments on characterizing the asphaltene precipitation effect on permeability reduction. The experiments are also unique in providing the precipitation effects on the end point relative permeability at Siw.

For quantifying the degree and scale of asphaltene precipitation a set of experiments are designed to induce permeability reduction along the flow direction. Then the plugged and unplugged pore ratios were quantified using SEM images taken at five different points from the core inlet. In all experiments, total plugging has occurred between 40 to 60-pore volume injection. It has also been found that within a distance of 0.3 total core length, approximately 80 % of the plugging has occurred indicating the ‘snowballing’ nature of mechanical entrapment.

Then the two major mechanisms of asphaltene deposition namely dynamic asphaltene adsorption and mechanical entrapment were quantified by reversing the flow direction. The reversal of the flow have initially resulted in approximately 80 percent permeability recovery, indicating that 80 percent of the permeability reduction is caused by mechanical entrapment. Then a period of simultaneously acting recovery and impairment mechanisms has been observed finally followed by impairment mechanism only. After the initial recovery period, a consequent flooding of one the cores with toluene were able to establish the original permeability. This additional recovery is attributed to removal of the adsorbed asphaltenes.
Control of Scaling Tendencies in an Effluent Water Injection Plant in West Kuwait Oil Fields: Laboratory Study
Authors: Salman M. , Al-Hashem A. , Carew J.
Published: December 2007

Scale inhibitors screening and evaluation study was conducted to minimize the possibility of scaling tendencies when effluent water is injected into the reservoir of West Kuwait oil fields. Static autoclave jar test and dynamic scaling rig were used to screen and evaluate six commercially available scale inhibitors. Five different effluent and formation waters were tested using the static jar test and dynamic scaling test rig under reservoir and surface conditions. The results of this scale inhibitor screening and evaluation study were judged upon efficiency to inhibit calcium carbonate (CaCO3) and barium sulphate (BaSO4) scales. The two most effective scale inhibitors to reduce both CaCO3 and BaSO4 scales were selected with optimum dosages. The first effective inhibitor was an aqueous solution of organic phosphate with an optimum dose of 15 ppm to control CaCO3 and 20 ppm to control BaSO4. The second effective inhibitor was a combination of organic amine and organic phosphates with an optimum dose of 20 ppm to control both CaCO3 and BaSO4.
Gas Process Displacement Efficiency Comparisons on a Carbonate Reservoir
Authors: Egermann P. , Robin M. , Lombard J-M. , Modavi A. , Kalam M. Z.
Published: December 2007

Secondary and tertiary recovery processes based on gas injection can represent a very interesting solution to extend the life of waterflooded reservoirs and maximize the oil recovery. However, the injection strategy needs to be carefully studied in order to optimize the overall sweeping efficiency. In particular, the impact of a possible water blocking on the recovery has to be addressed. For that purpose, a series of experiments was performed under reservoir conditions on a carbonate rock type, to compare the displacement efficiencies of a secondary gas injection, a tertiary gas injection and a SWAG (Simultaneous Water Alternated Gas) injection.

The experiments were carried out on composite cores, consisting of several carefully selected reservoir core plugs of the chosen rock type. The operating pressure was lower than the minimum miscible pressure (MMP) and reflected the current reservoir pressure. Phase exchanges were continually monitored during the hydrocarbon recovery, including the chromatographic analysis of the produced gas.

The final oil recovery resulting from the three types of experiments were very good (about 90% OOIP at surface conditions, after 6 PV injection) and quite similar within the experimental conditions, regardless of the sequence of gas injection. The low residual oil saturation (Sorg) values observed were consistent with competing processes of both viscous displacement of oil by gas and phase exchanges occurring between oil and gas. Due to the nature of the injected gas (rich gas from the first separation stage), a condensing/vaporizing process had to be considered. The SWAG injection speeds up the oil recovery by a mobility control of the water phase. This enhances the sweep efficiency by viscous drive. Water blocking effect was found to be negligible as it could be anticipated due to wettability consideration.

The influence of the fluid description (EOS) and the threephase relative permeability model on the simulation results was studied. An excellent agreement between simulation and production data was obtained using both gas/oil relative permeability data measured at ambient conditions on a restored composite core and an appropriate EOS (with 7 pseudos). The condensing/vaporizing process that strips the intermediate compounds from the oil phase to the gas phase was properly taken into account with this appropriate EOS. The influence of the three-phase permeability model ("geometrical construction" or Stone1) on the results was found to be small.
Integrated Workflow Applied to the Characterization of a Carbonate Fractured Reservoir: Qarn Alam Field
Authors: Zellou A. M. , Hartley L. J. , Hoogerduijn-Strating E. H. , Al Dhahab S. H. H. , Boom W. , Hadrami F.
Published: December 2007

This paper presents an innovative integrated workflow applied to the characterization of a carbonate fractured reservoir in order to generate an effective 3D Matrix Block Size (MBS) distribution based on all available data: geological, geophysical and dynamic production data. The MBS is a key factor determining heating and thereby recovery efficiency during steam flooding in a fractured reservoir. The MBS model allows simulating the complex flow and establishing reservoir management strategies that will optimize oil recovery and facility sizing.

The major difficulty in developing a 3D MBS model is the ability to account for the all the information pertinent to natural fractures in the field and develop an understanding of what geological characteristics are linked to the occurrence of fractures. Until recently most fractured reservoir modeling tools were limited to simple discrete statistical models. A new approach in fractured reservoir characterization, using primarily artificial intelligence tools, is presented in this paper. The methodology is based on the assumption that there is a complex relationship between a large number of potential geologic drivers (structure, faults, matrix characteristics etc.) and fractures. The combination of both the continuum fracture modeling (CFM) and discrete fracture network (DFN) modeling provides a quantitative framework for MBS distribution estimation, geological concepts and data integration. The application of this integrated workflow to the Qarn Alam field is presented in this paper.
An Overview of the Development of the Scarab/Saffron Project
Authors: Dick Will , Sharshar Abd El Raouf
Published: December 2007

The Scarab/Saffron Development was initiated by the signing of the West Delta Deep Concession Agreement between the Government of the Arab Republic of Egypt(A.R.E.), The Egyptian General Petroleum Corporation(EGPC), BG Exploration and Production Ltd(now BG Group) and Edison Gas International. Following the signature of the Gas Sales Agreement and Project Sanction, a Joint Venture Company called Burullus Gas Co comprising EGPC(50%), BG Egypt (25%) and Edison Gas International (25%) was formed.
Performance Enhancement by Applying RDBMS Tool as A Small-Enterprise Solution to Integrated Data Management - A Case from Kalol Field, India
Authors: Ghosh U. K. , Patra T. C. , Raghuvir Singh
Published: December 2007

Kalol field is a major oil-producing field of Ahmedabad Asset, ONGC. The field has 40 years of history with over 500 wells drilled and 11 potential hydrocarbon-bearing layers exploited. Over the years data has gathered differently into substantial dimension. A field-level integrated database system has been developed in-house using Microsoft Office's Access module. Apart from regular data management tasks, the package is designed to generate streaming input data files for two popular software. As the package is equipped with strong relational back-bone, data updating is instantaneous and it remains integrated sans any duplication or redundancy. The package is in use for Kalol field most effectively and indeed a suitable quick-run data management tool for any oil-field, small or large.
Comparison of Wellbore Hydraulics Models to Maximize Control of BHP and Minimize Risk of Formation Damage
Authors: Gil Isabel C. , Shayegi Sara
Published: December 2007

Underbalanced drilling is considered a technique for improving productivity, since the target zone in the well is drilled with bottom-hole drilling pressure lower than pore pressure in the target zone. These differences in pressure may minimize the risk of formation damage if the bottom hole circulating pressure is maintained lower than reservoir pressure at all times. For this reason, it is very important to have good knowledge of pore pressures and bottom hole circulating pressures and their variations while drilling.

The ability to accurately predict bottom hole pressure is critical for both designing an underbalanced drilling operation as well as for predicting the effect of variations during the actual drilling operation. Commercial models are available to calculate wellbore hydraulics for fluids used in underbalanced operations. Modeling is employed for designing and monitoring underbalanced drilling operations and for modifying operational parameters in response to changing conditions. It is also very important to realize that, in case the bottom hole pressure signal from the downhole tool is lost, it is necessary to rely on the model being used. If calibration has already been made and predictions agree with actual measurements there is more confidence in the model and the prediction that the system is underbalanced. Otherwise underbalanced conditions may not be guaranteed, and formation damage could occur.

Field data from oil and gas wells are used in this paper for comparing the prediction of bottom hole pressure using different wellbore hydraulic simulators against the actual pressure while drilling underbalanced. Results show which simulator and correlations give better predictions based upon characteristics of the wells and fluids type. The source of differences in results is examined and recommendations are made.
The Challenge Of Well Control In Under Balance Drilling And The Role Of Training In Meeting It
Authors: Malkowski Richard
Published: December 2007

In overbalanced drilling conventional well control is affected by using a hydrostatic pressure greater than the pore pressure. In under balanced drilling this differential is removed and bottom hole pressure is maintained at a value less than the pore pressure. Therefore there is a continuous "well control situation" during the under balance section.

To do this requires some form of rotating control device, drilling chokes, specialised fluids and different operating techniques.
A Closed Form Hydraulics Equation for Predicting Bottom-Hole Pressure in UBD with Foam
Authors: Guo Boyun , Sun Kai , Ghalambor Ali
Published: December 2007

A closed form and easy-to-use analytical model has been developed in this study for foam hydraulics. The analytical model fully couples the frictional and hydrostatic pressure components in vertical and inclined boreholes. The newly developed model together with screened rheological model was validated using bottom pressure data measured from two wells drilled with stable foams. The maximum difference between the model-predicted and measured bottom hole pressures is 9.2%. Theoretical analyses with the model indicate that injection GLR is a dominating factor affecting depth limit and ECD in stable foam drilling. In the practical range of GLR (1 to 20) and a gas injection rate limit of 2000 scfm, the maximum borehole depth is about 5000 ft where the lower limit of stable foam quality of 0.55 is reached. The new model was used in this study to generate depth limit and ECD curves that can be used for multi-gradient drilling on-shore and in deepwater development.
Re-Completion Techniques on Shallow Gas Wells Using Coiled Tubing Conveyed Fracturing
Authors: Thatcher Darren , Glanville Stephen , Zander Dennis , Jirges Harlan , Weishoff Jon
Published: December 2007

Hundreds of depleted shallow gas wells in the Saco, Montana area of the Northwestern United States have been found to have bypassed pay that until recently was believed uneconomical to recover. Wells in the area were traditionally completed with one production zone and were fractured by conventional means down the casing. The pay zones were then efficiently depleted through the use of siphon strings and flow line compression. Upon review of the well logs, it was determined there may be enough bypassed pay within the existing wellbore to continue producing the well as a multi-zone completion.

This paper outlines the logistics, execution, and evaluation of coiled tubing conveyed fracturing for depleted gas wells. Formations that were stimulated in this study appear to have similar characteristics to the thin producing lenses typically treated in Southeastern Alberta, Canada. The majority of the wells treated received up to six fractures and averaged 100,000 lbs of sand placed into each wellbore. The challenges and results from an initial pilot project are reviewed along with the subsequent multi-well project that followed.
New Boundaries for Cementing with Coiled Tubing
Authors: Wilson K. J. , Morrison D. , Sackash M. J. , Poole D.
Published: December 2007

Recently a contaminated cement squeeze was performed in the Gulf of Mexico using coiled tubing. The work was performed at 18,600 ft, 326°F bottom hole temperature, 12,000 psi pumping pressure and 9,000 psi chokeback pressure in a H2S, CO2 environment. Operationally this squeeze was a tremendous success and set several new benchmarks with regards to high-pressure coiled tubing operations.

This paper describes the reasons for using a contaminated cement squeeze under these harsh conditions, the standard procedure for this work, and the deviations from standard procedure made specifically for this well. The paper also discusses the importance of hydraulic modeling, fluid selection, the benefits of doing yard tests, and analyzing previous jobs to verify the models.
A Multi-Well Review of Coiled Tubing Force Matching
Authors: Craig S. H.
Published: December 2007

To increase the predictability of successful coiled tubing operations, a review of recorded versus predicted weights was undertaken for several Statoil operated Norwegian platforms. Results from thirty-three wells were analysed and showed that a coefficient of friction of 0.24 was applicable in most wells. Additionally, it was confirmed that deviation complexity, production rates and direction of travel had no effect on the friction coefficient.
Selective Tubing Access into Multilateral Wells in Upper Zakum Field: A Two-Well Case Study From Abu Dhabi
Authors: Dahroug Ahmed , Al-Marzooqi Ali , Al-Ansara Faisal , Chareuf Ali , Hassan Mahmoud
Published: December 2007

Branches in Level 1 and 2 lateral extensions traditionally have offered limited access. Coiled tubing (CT) intervention was limited to the main hole only, and thus stimulation of main reservoir targets was not possible.

A new system designed with a 2 1/8-in. outside diameter (OD) enables rigless intervention through the completion restriction. The system includes a reentry bottomhole assembly (BHA), which consists of a surface-controlled orienting tool and a controllable bent sub (CBS). The Discovery MLT* multilateral tool identifies the window of the selected lateral before attempting reentry, and confirms successful identification. The entry is visible at the surface through a software-displayed pressure log. The technique does not require a wired coiled tubing string; the corrosion-resistant reentry tool is operated solely by flow and is conveyed with standard CT equipment.

As proved by the success of the new reentry tool in Upper Zakum field selective matrix stimulation and nitrogen kickoff operations detailed in this paper, the need to bullhead huge acid treatments that result in major openhole washouts has been eliminated. These washouts can cause both poor acid distribution and prevention of future access to the lateral for CT logging operations.

This paper discusses the successful deployment of a selective multilateral entry tool that was utilized to access multilateral wells in Upper Zakum field, two case histories, and the method™s potential in Upper Zakum field.

The two case studies presented demonstrate the success of this system in reentering a desired lateral on the first attempt for matrix stimulation operations. Current developments that enlarge the scope of application to wellbore logging are under study.
A New Approach to Ultrasonic Coiled Tubing Inspection
Authors: Newman Kenneth R. , Lovell John
Published: December 2007

A field worthy method of accurately measuring localized coiled tubing (CT) wall thickness using ultrasonic (UT) techniques has been developed. This paper discusses the development of this new method, the system required to implement the method, and presents data from testing of the system.
Efficient Sand Cleanouts in Larger Wellbores Using Coiled Tubing: A New Approach Making an Old Problem Simple
Authors: Ovesen Monica , Sach Manfred , Laun Lyle , Gill Gregory E. , Henning Juel
Published: December 2007

Sand cleanouts using Coiled Tubing (CT) have been performed for as long as CT has been in service and still account for a large percentage of applications today. For larger, deviated wellbores, sand cleanouts become increasingly difficult, even with larger sizes of CT. Sand settling to the low side of the wellbore results in the formation of solids beds. In combination with the eccentric annular flow path created with the CT, substantial amounts of sand can easily be left behind. Current approaches to eliminate the solids bed involve using higher flow rates, or exotic and costly fluids, neither of which ensures complete solids removal in every case. These methods also typically spend a great deal of time circulating, after having reached the desired cleanout depth.

Using a specially developed cleanout tool and a computer simulator for solids transport provides an opportunity to optimize the operation for the removal of solids to near 100% efficiency, with all fluidizable solids being removed. Simplified operational procedures allow for making a more qualitative decision about the cleanout efficiency. This new, patented process is called "Tornado™".

In this paper, results from two case histories performed on subsea wells in the Norwegian sector of the North Sea are presented. Both operations were performed from semi-submersible rigs, with one representing the first use of 60.325 mm (2 3/8") CT from a floating platform in the Norwegian sector of the North Sea.

The process of removing the majority of sand from the wellbore with only one wiper trip will be explained, as well as a comparison of sand removal predictions from the computer simulator to actual conditions observed.

To-date, 3 cleanouts utilizing CT and the Tornado cleanout process have been performed inside 177.8 mm (7") and 244.5 mm (9 5/8") wellbores in the Norwegian sector of the North Sea. No indications of increased CT pickup weights or stuck CT were experienced while following the job program and established best practice guidelines for sand cleanouts. This indicates the Tornado cleanout tool’s reverse jetting action and circulating procedure does not increase the risk of stuck CT, while offering the advantages of a slick bottom hole assembly in larger, deviated wellbores. Centralizers are sometimes used to assist the cleanout process by disturbing the velocity profile around the bottom hole assembly. However, they also increase the risk of stuck CT and should be avoided.
Reducing the Cost of Coiled Tubing Cleanouts by Conducting Them Without Nitrogen
Authors: Portman Lance
Published: December 2007

One of the most common applications of coiled tubing is the removal of sand or other debris from wells. The typical operation involves circulating fluids down the coiled tubing and up the well. The fluids are designed to carry the sand from the bottom of the well to surface, without killing or over pressurizing the well.

Because most sand producing wells are under pressurized, gas is typically required to keep the hydrostatic weight of the return fluid column under that which the reservoir can support. This gas is typically nitrogen. Difficulties arise in many locations around the world where the supply of nitrogen is problematic, or at least very expensive. A cleanout method that does not require nitrogen removes the need for a timely, reliable and cheap source of nitrogen as well as the need for cryogenic pumps and tanks.

This paper details the use of concentric coiled tubing and a down hole jet pump to conduct cleanouts in the balanced or underbalanced condition without the use of nitrogen. This technique has been the subject of previous papers, demonstrating its applicability in difficult, deviated well profiles. This paper describes the enhancements made to the system to make it suitable to simple wells, focusing on low-cost, lower-tech operations as opposed to difficult applications. The first case histories are included.
Portfolio Optimization: Living Up to Expectations?
Authors: Campbell John M. , Bratvold Reidar B. , Begg Steve H.
Published: December 2007

This paper addresses some of our experiences in working with practitioners dealing with the adoption and implementation of formal risk and portfolio decision methods. The emergence of project investment case histories based on formal Decision and Risk Assessment (D&RA) methods provides a mixed bag of results. Though generally better than historical deterministic methods, the failures are just as illuminating as the successes. In our analysis of the case histories, we find that some of the failures can be attributed to several simplifications formalized in the process. In this paper we explore the impacts of three areas of simplification that, whilst wellintentioned, have potential to cause adverse initial reactions by professionals and management.

The first simplification covers the handling of the quality and validity of the input data used to generate the output metrics ultimately forming the foundation of the portfolio decisions. We show that ignoring intra-asset dependencies, or worse, using a P10,P50, P90 characterization derived from a base case plus an upside and downside (or even just guestimates) significantly distorts the real NPV distributions.

The second area arises from simplifying or ignoring the dependencies (or correlations) between the various assets. These inter-asset dependencies may be regional, fiscal, financial, global, technical, or life-cycle, to name but a few.

The final area of simplification is in optimizing against the expected value of the portfolio. The issue here is that there really is a distribution of possible returns for any given level of risk. If there are binding constraints then there is a substantial probability that the expected return will not be achieved. (This is analogous to the arguments that insist we need to look at the full distribution of NPV for an individual asset, not just its expected value). This problem can be overcome by applying stochastic optimization techniques.

Using a typical suite of assets that a company might select a portfolio from, we demonstrate that these simplifications cause some very real and, economically, very significant concerns. They result in selection of a sub-optimal set of assets and participation levels, which potentially leads to a different portfolio risk profile and lower returns than expected.
Production Based Probabilistic Economics for Unconventional Gas
Authors: Seidle John P. , O'Connor Leslie S.
Published: December 2007

Unconventional gas plays are often risky. To help understand the uncertainty inherent in these plays, probabilistic estimated ultimate recoveries (EUR's) can be employed. Once sufficient production data are available for a given play, production based probabilistic EUR's can be constructed.

Meaningful economics require introduction of a time component to such probabilistic EUR's. This study does so in two ways. First, detailed production data are used to construct probabilistic distributions for annual gas volumes. Secondly, probabilistic gas price distributions are constructed from pertinent histories. Distributions of gas volumes and prices are then coupled in Monte Carlo simulations to generate probabilistic economics. Examples are presented using production data from Raton coal gas and the Whiskey Buttes (Frontier Formation, low permeability gas field) in conjunction with Henry Hub and CIG price distributions.