bluuebunny/crossref_metadata_2025 huggingface dataset:
Versatile Expandables Technology for Casing Repair
Authors: Storaune Anders , Winters Warren J.
Published: December 2007

Three installations of a new expandable casing patch in 5 ½" production casing are described. During field trials, 2,530 ft and 8,380 ft patches were installed in Wyoming and Texas gas wells previously shut-in due to corrosion leaks. The third application was in a new-drill well where a 205 ft patch isolated holes in casing from a perforating gun misfire. All three patches pressure-tested successfully thus enabling the wells to be fracture stimulated and produced.

The product provides high-strength flush-bore expandable seals at the ends of a liner comprised of conventional OCTG pipes. Unique about this system is that the expansion mandrel becomes integral with the seal assembly to provide internal yield and collapse resistance comparable to the OCTG liner. A hydraulic setting tool powered via work string by a high-pressure/low-volume pump (i.e., typical BOP or tubing tester) drives the expansion mandrel into the patch body.

The product, built initially as a one-trip system, was simplified and made more reliable by running as a two-trip system. First, the lower expandable seals and polished bore receptacle are installed. Next, the spacer string with upper seal is stung into the lower receptacle and the upper seals are expanded. The system is versatile in that the upper expandable seal also provides a receptacle to which a tieback liner, production tubing or another patch can be attached.

The paper highlights job design and execution including use of casing inspection logs, problems encountered, system improvements and best practices resulting from this work.
Determination of Relative Permeabilities and Capillary Pressures by an Automatic Adjustment Method.
Authors: Chavent G. , Cohen G. , Espy M.
Published: December 2007

Drainage or imbibition experiments in laboratory are often interpreted by trial and error: the flow equations are solved for different values of petrophysical parameters and the best fit determined by successively adjusting calculated productions with measured ones. These methods can be slow and time consuming.

In this paper we propose an automatic adjustment method based on optimal control theory. The unsteady one dimensional biphasic flow differential equations have been rewritten so as to exhibit three linearly independent terms which are functions of relative permeabilities and capillary pressure. These three functions are determined by a least square technique following discretization of the equations by a mixed finite elements method.

Two types of experiments are needed to carry out the interpretation, one with a fast flow rate, the other with a displacement velocity representative of reservoir conditions.

Running the automatic adjustment scheme on the results of the two experiments mentioned above yields directly the relative permeability curves and the capillary term function. The capillary curve is deduced from the capillary term function.

Use of mixed finite elements significantly contributes to accuracy and stability in the solution of the equations. Furthermore, the method remains valid in the two limiting cases of hyperbolic (imbibition alone) and parabolic equations (Buckley-Leverett approximation).

We illustrate the method for oil displacements by water and gas and for imbibition. Very satisfactory results are obtained, A comparison is also made with results given by trial and error adjustment.
Two Phase Flow in Well-Flowlines
Authors: Yocum B.T.
Published: December 2007

Introduction

Effective oilfield planning in Arabia required approximate solution of the two phase flow problem in oil wells and flowlines. Stated in broad terms, the problem resolved to determination of well flowline potential (B/D) as a function of major system variables:Flowing bottom-hole pressure, reservoir pressure and temperature, productivity index.Crude characteristics; pressure - volume - temperature (PVT) relationships, viscosities, and composition.Depth of oil well, diameter of casing and tubing, length and diameter of flowline.Trap pressure (back pressure at end of flowline), ambient temperature, ground temperature.

Relationships developed for well-flowlines have maximum usefulness if they can be extrapolated to low reservoir pressures, representing future conditions, with confidence. It was therefore decided to develop the physical relationships from basic fluid dynamic and thermodynamic principles whenever possible rather than relying on existing empirical equations. The coefficients of the theoretically sound equations; friction factors, heat transfer coefficients, thermal gradients, etc., were then correlated for flowing mixtures of gas and oil in actual well-flowlines. For convenience, the oil well will be taken up first and the flowline afterwards. Then, the two will be combined to give the overall well-flowline relationships.
Scanning Electron Microscope-Cold Stage : Viewing Fluid Saturated Reservoir Rock
Authors: Schwartz Daniel E.
Published: December 2007

A single module cold stage unit has been interfaced with a Scanning Electron Microscope to allow for the observation of fluid (oil, brine, water, etc.) saturated reservoir rock. The module provides sample freezing, fracturing, and coating capability for the observation of fully saturated rock material at liquid nitrogen tempertures. The ability to observe fluids in place in sedimentary rocks has expanded our understanding of relative fluid distributions and has increased the usefulness of the S.E.M. for reservoir rock characterization.
Hydraulics of Drilling with Aerated Muds under Simulated Borehole Conditions
Authors: Zhou L. , Ahmed R. M. , Miska S. Z. , Takach N. E. , Yu M. , Saasen A.
Published: December 2007

Maintaining optimum circulation rates is important in aerated mud drilling operations. However, reliable predictions of the optimum rates require accurate modeling of the frictional pressure loss at bottom-hole conditions. This paper presents a mechanistic model for underbalanced drilling with aerated muds. Extensive experiments in a unique field-scale high pressure and high temperature flow loop were performed to verify the predictions of the model. This flow loop has a 150 mm × 89 mm (6" × 3.5") horizontal annular geometry and is 22-m long. In the experiments, cuttings were introduced at a rate of 7.5 kg/min, representing a penetration rate of 15m/hr in the annular test section. The liquid phase flow rates were in the range of 0.30 - 0.57 m3/min, representing superficial liquid velocities in the range of 0.47 - 0.90 m/s. Gas liquid ratio (gas volume fraction under in-situ condition) was varied from 0.0 to 0.38. Test pressures and temperatures ranged from 1.28 to 3.45 MPa, and 27 °C to 80 °C, respectively. Gas-liquid ratios were chosen to simulate practical gas-liquid ratios under downhole conditions. For all the test runs, pressure drop and cuttings bed height over the entire annular section were measured. Flow patterns were identified by visual observations through a view port. The hydraulic model determines the flow pattern and predicts frictional pressure losses in a horizontal concentric annulus. The influences of gas liquid ratio (GLR) and other flow parameters on the frictional pressure loss are analyzed using this model. Comparisons between the model predictions and experimental measurements show a satisfactory agreement. The present model is useful for the design of underbalanced drilling applications.
Planning for Drilling, Completing and Testing a Deep, Abnormal Pressure, Sour Gas Wildcat in Mississippi
Authors: Stair Mark A. , Rogers Ronald D. , Carlton Louis A.
Published: December 2007

Exxon has spudded and drilled to total depth a deep sour gas well in the South Jackson Area in Mississippi. This well is planned to be completed with a redundant pressure string concept using a high strength (150,000 psi minimum yield) corrosion resistant alloy. The use of this completion concept required larger hole sizes and heavier casing strings than have previously been used by other operators in this area.
Are You Prepared Before You Start
Authors: Bowden Joe R.
Published: December 2007

The search for oil and gas has led to more hostile environments below and above the ground. This, coupled with the experience level of today's rig crews, has led to a growing concern for human and environmental safety. This concern should not begin at the development of a crisis but should be carried back to the well planning stages. The success of averting or preventing a crisis usually lies with proper well planning.

A great deal of literature and technical knowledge is available today for the operator to assist him in the drilling of oil and gas wells. Tubular design, mud rehology, pore pressure determination, drilling equipment design, bit design, etc., have all become highly technical and are far superior today than 10 years ago. Extensive well planning has become a common practice for many of today's drilling departments but is not carried down the ranks to the field.

The planning of a successful adventure is important, but even more important is the correct implementation of the well plan. The importance of a spud meeting with the well site supervisor cannot be overemphasized. A spud meeting would review the mechanics of drilling the well, the necessary communications, company oriented paperwork, and kill procedure to be used if a kick is taken. Once the well site supervisor knows his level of responsibility for the particular job he will be more qualified to execute the well program.
Comprehensive Design Formulae for Hydraulic Fracturing
Authors: Cleary Michael P.
Published: December 2007

This paper provides a number of comprehensive algebraic formulae, with readily determinable coefficients, which can be used to predict the extent and width of fractures produced by fluid injection at specified rates or borehole pressures, when these are reasonably well-behaved functions of time. The fracture geometries described include as special cases the models currently in use for industrial design of hydraulic fractures, but extensions to allow variable fracture height are readily achieved. The formulae serve both to simplify the implementation of conventional models and to allow development of more realistic simulations which contain the rather idealised concepts of those models in their rightful place as components of a more general three-dimensional description. One such pseudo-3-D model is described in its simplest form; it allows physically credible tracing of length, height and width distributions under conditions of slow vertical spreading which a desirable stimulation treatment would achieve. All of the models admit quite general reservoir properties and frac-fluid behavior. A few popular applications are used to illustrate their power and simplicity.
Analysis of Mechanisms and Procedures for Producing Favourable Shapes of Hydraulic Fractures
Authors: Cleary Michael P.
Published: December 2007

The paper identifies some primary features of tectonic conditions, rock response and fluid rheology which can strongly affect the shape evolution of hydraulic fractures in representative reservoir formations. Numerous mechanisms are described, with emphasis on the question of fracture containment within regions of desirable transmissivity increase. Relevant natural characteristics include: contrasts of in situ stress, variations in material deformabi1ity/fractur-ability, and differences in permeability between pay-zones and adjacent strata. Various degrees of crack-arrest are possible but the dominant component of most mechanisms is the retardation of fracture growth caused by impedance to fluid flow. Artificial biasing of flow patterns may be achieved, by chemical or mechanical preparation of the region to be stimulated and by use of complex frac-fluid rheology. Implementation of these phenomena in practical designs typically requires detailed analysis with numerical models, but numerous recommendations can be made to improve conventional practises: for instance, fracturing pressures must be carefully limited, pretreatment can be helpful and rheology/proppant-scheduling can be exploited to much greater extents.
Electromagnetic Propagation Tool (EPT): Comparison of Log Derived and in Situ oil Saturations in Shaly Fresh Water Sands
Authors: Freedman R. , Montague D. R.
Published: December 2007

We have examined log and laboratory data on cores and/or sidewall samples from three Shell wells producing heavy crude oil from shaly sands containing fresh water of variable and unknown Rw. Using only downhole data from the EPT and a porosity tool we have derived oil saturations SOEPT and compared them with in situ saturations So inferred from laboratory and log data. Although the deviations of SOEPT from So exhibit a great deal of scatter, the results nevertheless demonstrate that one can identify the oil-bearing zones in this difficult log interpretation environment. The results are especially encouraging when one considers that values of SOEPT were obtained from a minimum log suite (specifically SP, EPT and density) without knowing the water resistivities, Rw, the cation exchange capacities, Qv, of the sands and without any other auxiliary data not obtainable from downhole logs. A detailed description of the EPT tool and its resultant log is given in order to provide the log analyst with a useful and self-contained reference for this new logging tool.
History Match Simulation of Serrazzano Geothermal Reservoir
Authors: Pruess Karsten , Weres Oleh , Schroeder Ron , Marconcini Rodolfo , Neri Giuseppe
Published: December 2007

The simulator SHAFT79 of Lawrence Berkeley Laboratory has been applied to field-wide distributed parameter simulation of the vapor-dominated geothermal reservoir at Serrazzano, Italy. Using a three-dimensional geologically accurate mesh and detailed flow rate data from 19 producing wells, a period of 15.5 years (from 1959 to 1975) has been simulated. The reservoir model used is based on field measurements of temperatures and pressures, laboratory data for core samples, and available geological and hydrological information. The main parameters determined (adjusted) during development of the simulation are permeabilities and much of the initial conditions.

Simulated patterns of pressure decline show semi-quantitative agreement with field observations. Field pressures decline overall somewhat more rapidly than predicted in the simulation. It is concluded that (i) the interface between overlying steam cap and deeper boiling aquifer remains stationary during exploitation; (ii) the aquifer boils approximately uniformly throughout in response to production.

Furthermore, the simulation suggests that (iii) there is cold water recharge and/or incomplete heat transfer from the rock due to fractures in the margins of the reservoir, and (iv) some steam flowing to the main well field originates from deep fractures rather than from boiling in the two-phase zones modeled.

Simulation methodology and ambiguity of parameter determination is discussed.
Non-Darcy Flow in Dissolved Cas-Drive Reservoirs
Authors: Kadi K. S.
Published: December 2007

Gas reservoirs have been simulated for turbulent (more appropriately visco-inertial) flow in the past. A study is extended to single-phase oil, and to two-phase non-Darcy flow in a solution-gas drive reservoir. The effects of normal sequence (increasing rate) and reverse sequence (decreasing rate) schedules, and the effects of liberation of gas on the Absolute Open Flow Potential (AOFP) and skin are considered. Analysis of the results obtained from the two-phase, one-dimensional radial model reveals that the oil non-Darcy pressure drawdown behaves like pressure drawdown in gas wells with turbulent flow. Formation flow capacity calculated from the constant rate drawdown test indicates that non-Darcy flow induces a skin which is rate dependent.

The performance of a depletion-drive reservoir obeying a non-Darcy type motion is compared to the performance of the same reservoir producing in a Darcy fashion. The pressure profile and the GOR curve are lower, and the gas saturation profile is higher for a given flowrate in the non-Darcy case in the range investigated. The non-Darcy AOFP is lower than the corresponding Darcy AOFP for a flow-after flow performance. Above the bubble point pressure, an increasing skin decreases the visco-inertial effects. When gas is present or is flowing, an increasing skin stabilizes the visco-inertial effects.
Application of Integrated Reservoir Analysis to Optimize Development Plan
Authors: Wang S. W. , Shivers B. , Setiawan Y. , Inaray J. , Harmawan I. , Fidra Y.
Published: December 2007

This work presents a methodology which uses nodal analysis, material balance, pressure transient analysis, and integrated production management (IPM) to determine reservoir boundary, original fluid in place (OFIP), and completion strategy for one of the reservoirs in West Seno field, the first deepwater development project in Indonesia.

The drainage area calculated from pressure test analysis compares favorably with that derived from seismic amplitude map. OFIP was used to (1) guide 3D simulation to study the potential of secondary recovery with water or gas injection and (2) build an IPM model to study optimal workover strategy.

Although reservoir size and OFIP were evaluated with various methods, the final results are very similar. This finding and successful history matching with IPM and 3D simulation models increase our confidence in the optimized development plan.
The Use of Vertical Seismic Profiles and Surface Seismic Profiles to Investigate the Distribution of Aquifers in the Madison Group and Red River Formation, Powder River Basin, Wyoming-Montana
Authors: Balch Alfred H. , Lee Myung W. , Miller John J. , Ryder Robert T.
Published: December 2007

The water resource potential of deep aquifers (2,000 ft to 10,000 ft) such as the Madison-Red River interval in the Eastern Powder River Basin of Wyoming-Montana is of great importance to support the future heavy water demands that coal and other energy development activities will place on the limited known water resources of the area.

We have used conventional well data, vertical seismic profiles, and surface seismic reflection profiles to see whether porous, water-productive Madison-Red River sections can be distinguished from barren sections in advance of drilling.

Our observations suggest that porous productive end members are identifiable on the basis of acoustic differences, as observed on reflected wave trains in the exploration seismic frequency range.
Characterization of Sulphate Scaling Formation Damage From Laboratory Measurements (To Predict Well-Productivity Decline)
Authors: Bedrikovetsky P. G. , Moraes G. P. , Monteiro R. , Lopes R. P. , Rosário F. F. , Bezerra M. C.
Published: December 2007

The formation damage in scaled-up production wells caused by incompatibility of injected and formation waters have long been known. Precipitation of salts results in permeability decline. Among the most onerous of all scaling species is that of sulphates, particularly barium and strontium sulphates.

We study effects of porous media on the BaSO4 scaling kinetics.

A new methodology for determination of reaction rate coefficient from coreflood tests consists of the sequence of diffusivity reaction free tests, of transient tests with chemical reaction, and of simultaneous injections of both injected and formation waters with quasi steady state concentration profiles for barium and sulphate ions. The diffusivity tests serve for dispersivity coefficient determination. Quasi steady state tests allow determination of the reaction rate coefficient versus velocity. The transient test data as compared with the mathematical modelling data validate the model and the data of steady state test data treatment.

An analytical model developed is used for treatment of quasi steady state test data. The transient tests are treated by a numerical model.

The main result of the work is proportionality between the reaction rate coefficient and flow velocity for the parameter range studied.
Experimental Design as a Framework for Multiple Realisation History Matching: F6 Further Development Studies
Authors: Alessio L. , Coca S. , Bourdon L.
Published: December 2007

History matching is traditionally complex and time-consuming: multiple parameters influence the match and their inter-dependency produces effects that are difficult to predict. Defining the match itself can be challenging, since various indexes or responses can be used: water breakthrough timing, pressures, layer contributions etc… Consequently, whilst multiple realisations methodologies are routinely applied for "green" field development planning, most of the time incremental activity screening on "brown" fields is done on a single matching realisation -"the" matched model - with little confidence that the full range of uncertainties is captured.

Experimental design provides a well-suited framework to tackle the challenge of multi-realisation history matching, following these key steps:

Selection of key parameters with variance analysis, Reduction of dimensionality by creating hybrid parameters, using techniques related to principle component analysis, Predicting matching domains: combination of parameters levels (once discretised) that are likely to generate a match. This greatly helps the likelihood of finding multiple matching realisations, covering the range of parameter variation.

This methodology was successfully applied in the F6 subsurface studies, aimed at screening field redevelopment opportunities. F6 is the largest gas field in the Central Luconia carbonate province, offshore Sarawak (Borneo), having a GIIP of more than 7 Tscf. With over half the reserves produced, well capacity is now threatened by the rising aquifer. In order to safeguard and possibly increase the reserves, a field review was undertaken to identify further development opportunities, and a multi-realisation approach was chosen to capture the effect of key subsurface uncertainties on those activities.

A total of 28 matching realisations were generated, covering the variation range of the identified key seven parameters whilst optimising the number of runs performed, thus saving time. Key to the success of the method lies in the integration of disciplines to allow the upfront identification of parameters and their ranges.

The screening of redevelopment options against those realisations allowed to establish the range of expected incremental reserves, assess risks, and form a sound basis for business decisions.
The Impact of Condensate Blockage and Completion Fluids on Gas Productivity in Gas-Condensate Reservoirs
Authors: Al-Anazi H. A. , Solares J. R. , Al-Faifi M. G.
Published: December 2007

Coreflood experiments were conducted on carbonate and sandstone cores from gas-condensate reservoirs in Saudi Arabia to assess the loss in gas relative permeability caused by condensate accumulation and water blockage. Field samples of condensate were used in these experiments to mimic two-phase flow around the wellbore region when the bottom hole flowing pressure dropped below the dewpoint. The impact of several fluids used as completion fluids was also investigated at reservoir conditions. Several solvents were evaluated to remove both condensate and water blockages.

Experimental results show that reductions of 70% to 95% in gas relative permeability were seen in reservoir cores due to condensate blockage. The studied solvents were found to be effective for enhancing gas relative permeability. This study also quantified the required methanol treatment volumes to increase gas relative permeability at lab conditions, which could be extrapolated to field conditions. The reduction in gas relative permeability was more pronounced during two-phase flow in the presence of water saturation due to the dual effect of condensate and water blockage. Methanol displaces retrograde condensate and maintains improved gas relative permeability well into the post-treatment production period.

Methanol-water mixtures were ineffective in removing condensate blockage and decreased gas productivity after their treatment. Methanol was effective in removing water from the cores. A mixture of isopropyl alcohol and methanol yielded similar favorable results as pure methanol. In summary, the evaluated solvents were all effective in removing condensate blockage from the core, delayed condensate accumulation, and enhanced gas productivity.
An Empirical Correlation to Predict Diamond Bit Drilling Rates
Authors: Duklet Clare P. , Bates Thomas R.
Published: December 2007

Diamond bit drilling tests have been performed at the Drilling Research Laboratory (DRL) in Salt Laie City, Utah. These tests were sponsored and supervised by the Shell Development Company. The tests simulated down hole drilling pressures on a typical diamond drill bit and oilfield formation. Variations of typical field operating variables were tested for penetration rate response. An empirical equation has been derived from the test results to predict diamond bit drilling rates.
Fiber Optics Used To Support Reservoir Temperature Surveillance in Duri Steamflood
Authors: Nath D. K.
Published: December 2007

In thermal fields, temperature profiles usually are acquired as part of a sound reservoir surveillance plan to manage heat in the ground. The conventional method used to acquire a temperature profile is to run a wireline log across the interval of interest, usually through tubing or casing in observation wells.

In Duri Steam Flood (DSF) production wells, it is not possible to run conventional temperature logs in producers without pulling out tubing pumps due to the complexity of the completion. One alternative to the real-time temperature profile in DSF producers is to use an optical fiber enclosed inside a steel tube strapped onto the outside of the tubing string and passed through the tubing hanger and top flange at the wellhead. The tubing hanger must be modified to accommodate the pre-installed fiber-tube installation.

The survey will collect temperature data that can be used to determine the temperature and extent of a steam chest and the temperature gradient in both overburden and under-burden. This information is necessary to set steam injection target rates using the Vogel and Neumann methodologies. The data are also useful in mitigating steam breakthroughs and eruptions, and to identify bypassed oil.
Gas Condensate Damage in Hydraulically Fractured Wells
Authors: Ravari R. R. , Wattenbarger R. A. , Ibrahim M.
Published: December 2007

The work in this paper is a result of a problem encountered in producing a low permeability formation from a hydraulically fractured well in South Texas. The well was producing from a tight gas condensate reservoir and there was concern about damaging the well if the wellbore pressure fell below the dew point. However, it turned out that condensate damage was not a problem. Lower wellbore pressures only resulted in higher rates.

This study used compositional reservoir simulation to model production for three situations; all having low permeability and hydraulic fractures. The simulation results verify what was observed in the field: lower wellbore pressure yields higher production rates. Although some condensate damage was observed below the dew point, none of the cases showed that lower wellbore pressures led to worse overall well performance. Even for the case of a very rich gas condensate, the optimum conditions correspond to the lowest pwf.

The results of this research may be a step forward in improving the management of gas condensate reservoirs by understanding the mechanics of liquid build-up. Although some wells may be "ruined" by low wellbore pressures, this was not evident in the cases in our work. The hydraulic fracturing seemed to reduce the condensate damage effect.
Understanding Corrosivity of Weighted Acids
Authors: Ke M. , Boles J. , Lant K. E.
Published: December 2007

Acids are frequently used to treat wells and remove formation damage during completions or in subsequent workovers. Sometimes, to prevent gas intrusion, excessive co-mingling of fluids and fluid density segregation, or to maintain hydrostatic pressure, a weighted acid will be applied to ensure successful treatment. Weighted acids are normally prepared by mixing acid with halide salts or concentrated halide brines such as sodium chloride (NaCl), calcium chloride (CaCl2), sodium bromide (NaBr), calcium bromide (CaBr2), or a combination of zinc bromide and calcium bromide (ZnBr2/CaBr2), etc. Selection of salts or brines is primarily based on the required properties of weighted acids and cost effectiveness. There are many publications related to corrosion and inhibition in acids; however, regarding corrosion behavior of weighted acids on tubular materials, relatively little information has been published.

Extensive laboratory testing was conducted to evaluate corrosivity of weighted acids prepared with different brines. Corrosion data is presented which indicates that depending on the brine applied, a weighted acid system may produce much higher corrosion rates over the same strength of acid prepared with fresh water (regular acid). When applied in weighted acids, some corrosion inhibitors or inhibitor packages qualified for regular acids do not provide adequate corrosion protection on regular oilfield tubulars. Also presented are evaluations of the weighted acids with regard to compatibility and effectiveness of the acids to maintain their strength and dissolution properties.
A Constitutive Equation for Nonlinear Stress-Strain Curves in Rocks and its Application to Stress Analysis Around a Borehole During Drilling
Authors: Morita Nobuo , Gray K. E.
Published: December 2007

The stress-strain behavior of Berea, Ohio, and Pecos sandstone was measured intensively under triaxial loading paths. Both compression and extension tests were performed at different pore fluid pressures. These tests showed that four modes can arise in the stress-strain curves up to failure: an initial nonlinear portion; linear portion; a final nonlinear portion; and volume change of the rock maxtrix due to pore fluid pressure. The characteristics of these modes were studied, and a nonlinear model was developed to represent the important characteristics, i.e., the four modes, of the behavior of sandstones by means of a constitutive equation in such a way as to satisfy certain mathematical requirements.

A finite element model using nonlinear stress-strain relationship was developed which simulates the stress state of a structure up to failure. The finite element model was used to predict fracture pressure around a borehole during drilling. The shape of the borehole is either circular or elliptic, and the tectonic stress is directional. Since the nonlinear stress state depends upon loading history, the loads were applied incrementally, simulating phenomena occuring during the drilling process. It is shown that use of conventional linear stress-strain behavior gives significantly erroneous results for well stability problems.
The Development of an Optimal Artificial Neural Network Model for Estimating Initial, Irreducible Water Saturation – Australian Reservoirs
Authors: Goda H. M. , Maier H. R. , Behrenbruch P.
Published: December 2007

Initial, irreducuble water saturation, Swir is an important parameter that needs to be determined accurately when attempting to characterize hydrocarbon reservoirs. Swir is also one of the key parameters in relative permeability relationships. Furthermore, an unrepresentative value of Swir may lead to invalid residual oil saturation estimates when the latter is correlated with the former.

Swi may have a dependence on several other parameters, including: absolute rock permeability, porosity, pore size distribution and capillary pressure. The above parameters are directly influenced by geological deposition and subsequent changes, such as diagenesis effects (for example clay-filled pores). It is a common practice to measure Swir utilizing representative core plugs by measuring capillary pressure with a centrifuge, at speeds equivalent to the maximum representative (reservoir) capillary pressure. However, a semi-empirical model that could estimate Swir to a good degree of accuracy would be of significant value.

Over the last few years, artificial neural networks have found their application in petroleum engineering. In some cases such models have outperformed models employing conventional statistical and regression analysis. In this study, an Artificial Neural Network (ANN) model has been developed for the prediction of Swi (specifically irreducible saturation, Swir) using data from a number of onshore and offshore Australian hydrocarbon basins. The paper outlines a methodology for developing ANN models and the results obtained indicate that the ANN model developed is successful in predicating values of Swir over the range of data used for calibration. This neural network based model is believed to be unique for Australian reservoirs
Enhanced Oil Recovery in Malaysia: Making it a Reality
Authors: Hamdan M. K. , Darman N. , Hussain D. , Ibrahim Z.
Published: December 2007

A considerable amount of hydrocarbon resource is estimated to remain in the ground even after primary and secondary recoveries in the fields. As of 2003, the estimated oil-in-place from the forty-seven producing fields in Malaysia stand at about 20.1 BSTB, with a cumulative production of 4.9 BSTB and reserves of 2.5 BSTB1. This translates to an averaged recovery factor of only 36.8 percent for producing fields in Malaysia. For this reason, the remaining oil-in-place of 12.7 BSTB i.e. 63.2% of STOIIP will be the prime target for Enhanced Oil Recovery (EOR) projects. On top of the value that could be gained through EOR applications, most of the fields are already entering maturing stage for primary and/or secondary depletion with declining oil rates and increasing water-cut and GOR trend. This situation will further merit the application of EOR processes. However, to date, there has been no full-field application of EOR in Malaysia, with the exception of a pilot WAG project in Dulang field2,3 and MEOR stimulation project in Bokor field4–6.

In 2000, a screening study on seventy-two (72) reservoirs in Malaysia has identified almost a billion barrels of additional reserves that can be achieved through EOR. Majority of these potentials resides in a few major reservoirs, which carries about 60% of the total EOR potential7. The screening study has also identified several key EOR technologies that are most applicable in Malaysia, namely gas injection, chemical injection, and microbial. Thermal processes were investigated but have been ruled out due to the operational, properties of reservoir fluid, safety and commercial limitation of the methods for Malaysian offshore applications. However, transforming those potentials into real projects may face some challenges and change of operating philosophy. Factors such as facilities condition, sources of injection gas, reservoir characterization, technology applicability, and commercial aspects will play an important role in planning for an EOR projects in Malaysia.

This paper presents the possible opportunities that could be realized by EOR applications, and discusses issues and challenges including change of mindsets required in making EOR a reality in Malaysia.
Emission Characteristics of a Modified CNG Gasoline-Cycle Engine
Authors: Kalam M. A. , Masjuki H. H. , Amalina M. A. , Abdesselam H. , Mahlia T. M. I. , Aslam M. U.
Published: December 2007

This paper presents the experimental results carried out to evaluate the exhaust emissions and performance evaluation of a computer integrated bi-fuel spark ignition engine that has been retrofitted for two fuels namely compressed natural gas (CNG) and base fuel gasoline, operations under steady state with lean burn condition. The used engine was a Proton Magma 4-cylinders spark ignition engine. The emission results such as CO, HC and NOx were measured and compared between the above two fuels. A locally produced three way catalytic converter (TWC) consisting of platinum (Pt), palladium (Pd), cerium oxide (CeO2) and rhodium (Rh) was used to assess the emissions. The CeO2 was used in TWC as an oxygen storage capacity (OSC) to enhance the oxidation process for CO and HC oxidations.
Application of Empirical Data in Forecasting Water Flood Behavior
Authors: Schauer P.E.
Published: December 2007

The use of empirical data to validate injection predictions and to prepare oil production forecasts is described. Histories of typical inputs show that reasonably reliable injection predictions can be made from equations based on Darcy's Law. The production performance of five Illinois floods is presented in a graph of accumulated increased recovery versus accumulated water injection per acre-ft, thereby permitting comparisons and forecast independently of time and input rate. The various steps used to apply this empirical data to a forecast are described, beginning with the method of estimating the accumulated injection necessary to achieve first production increase. Flood performance indicates this to be a function of permeability heterogeneity. The forecast of subsequent behavior is shown to consist of selecting the most appropriate empirical curve to use as a guide, with its selection based on relative reserves and degree of confinement. The introduction of time and rate is described as a stepwise integration of the accumulated production versus injection curve at the forecast injection rate.
Computerized Pressure Transient Data Analysis for Vertically Fractured Tight Gas Wells
Authors: Sinha Mihir K. , Padqett Larry R.
Published: December 2007

A procedure for analyzing short-term transient pressure (well test) data for a vertically fractured gas well is presented. The analysis provides unique estimates of important reservoir, well bore and fracture parameters by simulation and matching test data. The parameters developed can then be used to forecast the performance. The simulator is primarily designed around analytical techniques, utilizing published dimensionless pressure drop functions for a vertically fractured well system1,2–4 as well as for wellbore storage effects.16 By using this procedure practicing engineers will considerably lessen time and resources involved in analyzing well tests, while obtaining more reliable interpretations.

The procedure is designed to consider the entire range of the available drawdown and buildup data while minimizing user intervention. The model considers the effects of fracture conductivity, fracture length, fracture face damage, formation flow capacity or permeability, wellbore storage, fracture storage, and variable rates of flow during the test period, as well as the effect of producing time on the buildup behavior.

Several examples of actual field test data and their analysis using this procedure are presented. It is cautioned that the method finds best application when a single pressure drawdown followed by a buildup is available for a simple, homogeneous and uniform reservoir geometry. Furthermore, the well should be cleaned of fracturing fluids and a stabilized static pressure must be obtained prior to conducting the flow test. Finally, single phase gas flow should occur both in the reservoir and the wellbore for any meaningful analysis of the data to be possible.
Electrochemical Analysis of Surfactants for Microemulsion Flooding
Authors: Becker Michael C. , Glover Charles J. , Darby Ron , White Ralph E.
Published: December 2007

A previously reported indirect Polarographie method gave fair analytical results over a wide range of concentrations of SDBS in solutions containing NaCl or hexane. A modification of the method allowed analysis of the surfactant in the presence of isopropanol, although with somewhat reduced accuracy. The method performed well for an alkyl-ortho-xylene sulfonate.
Economic Appraisal of Thermal Drive Projects – A New Approach
Authors: Williams Richard L. , Brown Susan L. , Ramey Henry J.
Published: December 2007

Because of rapid increases in oil prices, oil companies have begun to re-evaluate recovery projects that were once considered economically unattractive. High on the list of new investment opportunities are thermal oil recovery projects. The combination of price increases, investment incentives (such as tax credits and subsidies by the Federal government), and proven superior recovery performance over other enhanced oil recovery methods has made many thermal recovery projects appear economically attractive.

To evaluate a thermal recovery project; reservoir, production, and economic parameters must either be known or assumed. Many numerical models have been developed to simulate existing projects and match actual production data. However, these models are often unduly complex and employ assumptions which reduce their applicability to a particular reservoir. Also, computer time and costs may prohibit an in-depth study of a reservoir.

Because thermal recovery projects require a substantial capital investment, a detailed reservoir and economic analysis is imperative in order to optimize oil production and revenue, maximize profits, and attain a good rate of return on investment. This paper presents a method to facilitate the estimation of oil recovery by either continuous steam injection or in-situ combustion, and generate a cash flow estimate based on the production schedule of each process.

It is assumed that the reservoir parameters are known, or can be obtained from conventional logging and laboratory methods. A synthesis of heat and mass balance equations presented in the literature is used to estimate oil production. A discounted cash flow is generated based on a probability distribution of the oil price, fuel price, capital costs, and operating costs. Discounted net present worth is graphed against the injection rate of steam or compressed air, and an optimal injection rate can be determined.

This method was developed to allow management to decide whether steam injection or in-situ combustion will be the most economically attractive process in the field. Parameters such as injection rates, pattern size and type, and efficiency may be changed either to describe a particular field application or to optimize the production schedule of a heavy oil recovery project. Application of this model to existing projects shows that for different parameters, either in-situ combustion or continuous steam injection will be the more economically attractive in the field.
Comparative Analysis of Pump-Off Control Systems for Field Applications
Authors: Amezcua Joe D.
Published: December 2007

One of the most controversial subjects related to the production of reservoir fluids is the application, field acceptance, and reliability of automatic pump-off control (POC) devices to rod pumped wells. Pump-off controllers made by three manufacturers were selected for an extensive evaluation in the McElroy field. Results indicate that the controllers do offer an economical means of operating rod pumped wells and that field acceptance is attainable.
Corrosion Monitoring on Rod-Pumped Wells Using Linear Polarization Probes
Authors: Shehorn L. Steve
Published: December 2007

Linear polarization instantaneous corrosion rate probes have been successfully used to optimize corrosion inhibitor treatments on producing oil wells, utilizing a wellhead bypass loop which allows water separation and collection when readings are to be taken. Well failures and corrosion inhibitor costs have been reduced simultaneously with linear polarization monitoring in two of Shell Oil Company's most corrosive fields in the Permian Basin of West Texas and New Mexico.
Success Story To Produce 200 MMscfd of Gas From Mutiara
Authors: Prihartono Y. A. , Riksa A. P. , Affan S. R.
Published: December 2007

Mutiara Field is one of four fields in VICO Indonesia, East Kalimantan that located in southern of the contract area. The central processing plant of Mutiara Field is originally designed for processing 165 MMscfd gas. In 2002–2003, some planned work programs were done successfully that include 5 well workover, installation of additional one MP compression unit and 2 well drilling program. The success of these work programs became apparent that Mutiara could produce more than 165 MMscfd. However, the plant throughput was limited by flare system capacity and gas dehydration capacity. So, the challenge was to overcome the capacity limit at minimum cost to allow Mutiara to increase sales gas export.

Some inter-multidisciplinary studies were conducted to solve the problem, to find the most suitable and most economic solution. The study concluded that there are two options to process gas more than plant capacity limit that are: installing additional flare system or to modify plant's overpressure protection system. The last option was selected based on time and cost justification. This modification is to cease incoming gas to the plant in order to maintain gas inside the plant below the flare capacity in case of overpressure occurred in the event of process upset.

Other problem that exists is limitation of dehydration unit to absorb water in the gas until the allowable limit. Overhaul dehydration unit had been done to improve its performance. This was also to include clean up and pressure testing of all equipment associated. Also, some pipeline debottlenecking projects at outlet plant were done to reduce plant outlet pressure that also supports operation of the plant.

The above changes were made at almost no capital cost, allowed Mutiara to produced gas at 200 MMscfd started on mid of 2003.
CO2 Injection in Carbonates
Authors: Izgec O. , Demiral B. , Bertin H. , Akin S.
Published: December 2007

Started as an EOR technique to produce oil, injection of carbon dioxide which is essentially a greenhouse gas is becoming more and more important. Although there are a number of mathematical modeling studies, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to characterize relevant chemical reactions associated with injection and storage of CO2 in carbonate formations. Porosity changes along the core plugs and the corresponding permeability changes are reported for differing CO2 injection rates and with differing salt concentrations. CT monitored experiments are designed to model fast near wellbore flow and slow reservoir flows. It was observed that permeability initially increased and decreased for slow injection cases. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. The experiments were modeled using a commercial simulator where solution and deposition of calcite were considered by means of chemical reactions. The calibrated model was then used to analyze field scale injections. It was observed that solubility storage of CO2 is larger compared to mineral trapping.
Downhole Deployment Valve – Case History
Authors: Timms A. , Muir K. , Wuest C.
Published: December 2007

During Underbalanced Drilling (UBD) a dilemma arises over which practice to use whenever the drill string has to be tripped out of the hole. Options are to kill the well, which may cause formation damage and defeat the object of UBD, to use a snubbing unit, or to trip with a live well, both of which have serious safety and cost implications. Setting a packer which is subsequently pushed down the hole on re-entry has been attempted on several occasions with varying degrees of success, but can only be used for completion operations and not for routine bit trips.

The Downhole Deployment Valve (DDV) was developed specifically to address this issue and provides the capability to close off the well at depth, allowing the wellbore above to be de-pressurised and thereby greatly facilitating tripping operations. When the DDV is closed, reservoir pressure reaches balance point below the valve, but the wellbore above is vented, which eliminates the "pipe light" condition completely and removes the need for snubbing. The DDV is a full-bore casing valve, hydraulically controlled from surface via control lines; it is run with the casing and can be cemented in place.