bluuebunny/crossref_metadata_2025 huggingface dataset:
Tracer-Test Simulation on Discrete Fracture Network Models for the Characterization of Fractured Reservoirs
Authors: Lange A. , Bouzian J. , Bourbiaux B.
Published: December 2007

The presence of fractures at various scales affects the flow dynamics within a reservoir, thus casting uncertainty on the assessment of the field productivity and reserves. Methodologies and tools are now available (i) to reconstruct geologically-realistic models of the fault/fracture network (ii) to turn these models into simplified conceptual models usable for field-scale simulations of multi-phase production methods. However, a critical intermediate step remains that of validating the geometry of the geological fault/fracture network and characterizing it in terms of flow properties.

An original 3D Discrete Fracture Network simulator enabling one to fulfil this characterization step has already been presented by the authors'. This simulator can compute the single-phase flow response of any type of fractured reservoir, whatever the scale, density and connectivity of fractures. An extension of this simulator to compute tracer tests is presented in this paper. Compared with pressure tests, tracer tests may provide additional information about the reservoir heterogeneity due to the convective nature of these tests.

This simulator is based on the dual-medium concept applied to an explicit representation of the geological model of fault/fracture network and matrix medium. The transport and dispersion of non-reactive tracers are modelled by introducing a convection-dispersion equation into the existing dualporosity flow model. A hybrid scheme discretizes the convective term implicitly within densely fractured regions for stability purposes, and explicitly via a double-upstream scheme everywhere else for reducing spurious numerical dispersion.

After demonstrating the reliability of this tracer model on validation cases, a realistic case that combines diffuse fracturing and major objects such as seismic and sub-seismic faults is studied. Tracer tests are simulated for wells in a five-spot injectionproduction pattern. Effects of a fracture/matrix tracer exchange as well as a Taylor-Aris dispersion on breakthrough curves are analyzed. The potentiality of tracer responses for providing information on the distribution of reservoir heterogeneities is discussed.
Simulation of Prudhoe Bay Field Interference Test
Authors: Myers Gary Allen , Johnston Ron D. , Mainwaring John R.
Published: December 2007

An improved reservoir description of a Prudhoe Bay field water injectivity test site was obtained by simultaneously history-matching interference, pressure buildup and production history data with a black oil simulator. Water is currently being injected in a Sadlerochit reservoir inverted, five-spot pattern on the east side of the field. Pressure data were obtained prior to starting water injection.

Interference testing was conducted by successively shutting in and producing each of the four corner wells, which are field production wells, and observing the pressure response at the water injection well in the center of the pattern. Pressure changes, varying from 2 to 8 psi, were measured with a downhole, high-sensitivity, quartz-crystal pressure transducer. While small, the pressure changes were measurable because two major shale complexes exist between the test interval and the large Prudhoe Bay field gas cap overlying the test area. Well spacing varied from 1600 to 2400 feet. Pressure buildup data were recorded for all five wells.

A consistent reservoir description was developed from geological and engineering data. Interference and production history data were history-matched with an XYZ simulator and pressure buildup data were modeled with an RZ simulator. The upper shale complex is sealing, while the middle shale complex, lying immediately above the observation well perforations, allows some vertical communication. Type-curve matching the interference test gave much greater krokh/μ values for the tested interval than the XYZ history match. This occurred primarily because the interference test actually investigated zones above the tested interval.
Optimization of Reverse Osmosis Treatment of in Situ Wastewaters
Authors: Kasper Dennis R.
Published: December 2007

This paper identifies and discusses optimization of wastewater concentration and disposal alternatives for wastewaters generated by in situ solution leaching. Disposal alternatives considered include: 1) deep well injection; 2) evaporation ponds; 3) reverse osmosis (RO) concentration plus deep well injection, and 4) RO concentration plus evaporation ponds. Factors affecting the RO process and other disposal processes include: flushing volume required for restoration, recovery of RO system, degree of pretreatment and restoration pumping schedule.
Petroleum Geology of Baltimore Canyon Trough
Authors: Mattick Robert E.
Published: December 2007

Exploration activity to date on the U.S. Atlantic Continental Shelf includes 3 oil and gas lease sales and the drilling of 5 deep strati-graphic test wells and 26 wildcat wells. Wildcat drilling in the Baltimore Canyon trough has been concentrated in the vicinity of the Great Stone dome and along the shelf edge. The Great Stone dome, a large domal structure inferred to be associated with an Early Cretaceous mafic intrusion, appeared to be one of the largest and most promising single structures on the shelf on the basis of the interpretation of seismic data. Six wells have been drilled on the structure, but no shows of oil or gas have been reported.

Results of wildcat drilling along the outer edge of the Continental Shelf have been more encouraging. Significant shows of natural gas have been reported from 3 out of 14 completed wildcat wells. The combined initial flow rates were about 2 million m3 per day (68.5 million ft3 per day) from Upper Jurassic sandstone beds at depths of about 4,000 m. An additional test, at one of these wells, flowed 48.4° gravity oil at the rate of 100 m3 per day (630 barrels per day) from a thin bed of Lower Cretaceous sandstone. A commercial size field, however, has not been established.

In the Baltimore Canyon trough, analysis indicates that shelf sediments have a relatively low potential for the generation of liquid hydrocarbons, but indications are favorable that natural gas could have been generated below a depth of 3,000 m. However, sandstone porosities deteriorate below 3,000 m, and at these depths, the Jurassic sandstone beds may lack lateral continuity.

Tracts to be leased in upcoming sales will extend out to water depths of 2,500 m. In the deep-water area beneath the Continental Slope, the interpretation of seismic data suggests that the shelf prograded seaward during Jurassic time. Consequently, Jurassic shelf facies containing potential reservoir rock may interfinger with slope facies that could contain source rock capable of having generated liquid petroleum. In spite of the huge investments of money that will be required for deep-water exploration, the possible presence, under the slope, of complex extensional-fault patterns, reef complexes, and salt diapirs will probably encourage interest in upcoming sales.
Eastern Tight Sands, A Stimulation Assessment
Authors: McKetta Steven F. , Koziar Gregory , Cook Louis S.
Published: December 2007

This paper is an evaluation of massive hydraulic fracturing and dendritic fracturing applied to four tight gas sands of the Eastern United States. A total of ten fracturing treatments were performed in the Berea, Benson, Clinton and Medina formations. The objective of this program was to determine whether a meaningful productivity increase could result from the application of new fracturing techniques over that of conventional hydraulic fracturing and/or explosive shooting. The small number of test wells, coupled with a wide range of test results and other geological factors make it difficult to draw definitive conclusions.
Financing the Appalachian Oil and Gas Industry
Authors: Riley Thomas E.
Published: December 2007

In recent years, the Appalachian area has experienced a resurgence of oil and gas drilling and development. Increases in prices and the outlook for continued growth in the value of oil and gas has generated this growth in activity. Most of this growth has come from the smaller, independent, operator and contractor. It is these companies who must rely on additional outside capital to achieve their growth. This capital can be generated either from new investors or from debt. This paper will deal with the various methods of securing and structuring debt for these different facets of the oil and gas business in the Appalachian area.

For the small, independent oil and gas or contracting companies, which comprise the majority of the business in the Appalachian area, the only available major debt structure is secured lending. Secured lending means that banks will loan money to a company using a part or all of a company's assets as collateral. For a contractor, this collateral is his equipment; for a pipeline owner, it is his pipeline and sales and purchase contracts; and for the producer it is his oil and gas reserves. It is the bank's role, then, to determine (1) the value of this collateral and whether it will generate sufficient cash flow to pay interest and retire debt, as well as (2) the borrower's financial responsibility, character, integrity, business stability and potential, and business relationship to the bank. This latter determination can be established with financial statements, earnings reports, business references, and credit reports. Determining the value of collateral presents a more difficult problem. For equipment, this can be done through an appraisal; in the case of oil and gas reserves, this requires a property evaluation by the bank's oil department or an outside consultant.

Capital requirements for drilling and service companies are usually for new or additional equipment. This equipment, then, is the collateral available for financing. Banks traditionally loan on the order of 80% of the purchase price of the equipment. The term of the loan is usually three to seven years depending upon the physical life of the machinery, area of activity, and company/bank relationship.
Development Planning for a Group of Oil Fields
Authors: Sullivan Jan
Published: December 2007

The use of an integrated model for planning the development of a group of onshore oil fields is reviewed. The planning problem is identified as one of finding a minimum cost strategy for developing and maintaining capacity to meet specified production goals over the lifetime of the reserves. The strategy identifies a schedule of production and injection for each reservoir, together with an installation schedule for any necessary additional equipment.

The planning model uses optimisation techniques to select the development strategy. This enables a wide range of strategies to be compared in an efficient and consistent manner. By specifying a suitable objective to the model, the economic life of the reserves for a particular target production and crude price profile can be found. This analyses may be used to estimate the minimum crude price required to make a given production profile economically viable.

The application of the planning model in the planning process is discussed in relation to the use of simulation techniques. The two methods are complementary. The results of the integrated model identify the most appropriate production strategy for each reservoir within the context of the complete system. This can then be validated through individual studies of the reservoirs and of the surface facilities.
Geological Interpretation of Oil Entrapment in the Zubair Formation, Raudhatain Field
Authors: Al-Rawi Munim M.
Published: December 2007

The purpose of this paper is to interpret geologically the oil entrapment in the Zubair Formation at the Raudhatain Field which is essentially barren at the neighbouring Sabriya Field although it is structurally high in the latter.

The Zubair Formation is of Early Cretaceous age and consists of sands and sandstone intercalated with siltstones, shales and few thin limestone beds. The average total thickness of the formation is 420 m (1380 ft).

The available data showed that the formation contains three potentially productive zones with many sand pools separated by shales. Analysis of the data showed that at the end of Zubair time, the upper reservoir was structurally higher at Raudhatain than Sabriya by about 16.5 m (54.4 ft), taking into account constant compaction. However, the present structural relief of the upper reservoir at Sabriya is about 29.4 m (98 ft). This gives a structural growth at Sabriya of about 46 m (152 ft).

Petrographic study of the sandstones showed drastic differences in porosity. The reservoir sands are very clean quartzite with average porosity of 20%. The aquifer sandstones however, show a reduction in porosity to about 7%.

It is interpreted that oil accumulation in the Zubair Formation at Raudhatain represent a case history of a "paleotrap". Oil migration occurred early before sands diagenesis. Oil entrapment was sealed off and with subsequent structural growth the oil frozen-in and did not migrate to Sabriya structural high and retained in situ. Secondary migration from the Zubair reservoir to higher horizons was postulated through growth faults at the Raudhatain. It is suggested that the relation between structural growth and reservoir characteristics should be investigated in the Arabian region to outline paleostructures which are open and presently unprospective, while they may contain important frozen-in accumulation.
Sedimentary Response to Tectonic and Eustatic Changes: an Example From the Mid-Cretaceous Wasia Formation, Saudi Arabia
Authors: Entsminger Lee D.
Published: December 2007

Deposition of the dominantly siliciclastic Cretaceous Wasia Formation (Albian through Turonian) in Saudi Arabia was initiated when tectonic movement uplifted a portion of the Arabian Shield. The magnitude of this uplift was greatest to the north as evidenced by the Pre-Wasla Unconformity, The Wasia, which is normally conformable to the Aptlan Shu'alba Formation, overlaps increasingly older formations from the Cretaceous Biyadh in the south to the Lower Devonian carbonates in the north. The primary sources of the Wasia sediments are the older formations eroded when the Pre-Wasla Unconformity was active. Feldspar, heavy mineral and quartz type distributions within the Wasia members suggest that the Arabian Shield was not a major contributor of sediments for the Wasia until the Wara member was deposited in late Albian Time.

The depositional sequence of the Wasia is reconstructed from evidence derived from outcrop, cores, and various subsurface maps. Eustatic cycles documented worldwide are correlated with the Wasia members, with limestone units representing Mid-Cretaceous transgressions.
Proper Fluid Pretreatment to Minimize Hydrogen Sulfide Dangers
Authors: Samuels Alvin , Wendt Richard P.
Published: December 2007

The potential hazards in the drilling, completion and/or servicing of wells containing hydrogen sulfide are described. A new generalized mud theory is used to calculate the level of corrosive or poisonous gas contamination due to varying amounts of hydrogen sulfide and carbon dioxide entering a mud stream as dependent on the mud's buffering capacity and alkalinity. It is demonstrated that an intrusion of gas containing as little as 0.5 mole percent hydrogen sulfide can create hazardous conditions. Even highly alkaline muds are predicted to have severely limited ability to neutralize acid gas intrusions and cannot be relied on for safety.

The important need for pretreatment of the muds to remove the hydrogen sulfide rather than merely neutralize it is described. Published laboratory kick simulation experiments and documented field results show that proper scavenger pretreatment and monitoring of the mud can protect against a well kick producing 10 million cubic feet (2.83 × l05m3) per day of sweet gas and 500,000 cubic feet (1.42 × 104m3) per day of hydrogen sulfide.
Productivity Testing Using Production Logging Techniques
Authors: Weiss Ernst N. , Taylor James G. , Toronyi Robert M.
Published: December 2007

A method of individual zone productivity and inflow performance relationship testing has been employed in two prolific offshore oil fields.

The procedures involving downhole measure ment of flow and pressure data using production logging combination tools are explained.

This testing approach conveniently obtains individual zone productivity inform at ion as well as general PI data, and is therefore useful for delineating important reservoir characteristics. Field results from carbonate and sandstone reservoirs are presented and discussed.
Carbon/Oxygen Or Resistivity/Pulsed Neutron Logging - A Case Study
Authors: Kerr Michael E.
Published: December 2007

The carbon/oxygen log is evaluated for measuring water saturation in observation wells containing a mixture of low salinity injected water and saline formation water. Good results are obtained when the reservoir nears depletion, but the tool is adversely affected by a mud filtrate annulus when an oil column remains in the reservoir. Combining resistivity and pulsed neutron logs gives a more accurate picture of reservoir behavior under these conditions.
Telemetered Surveillance and Control of an Onshore Gas Field
Authors: Handyside Christopher B.
Published: December 2007

A Supervisory Control and Data Acquisition (SCADA) system has been installed in Bahrain's Khuff gas field to carry out surveillance and control of the remote dehydration and transmission facilities. The system has proven to be a valuable operating tool in an operation where heavy load swings and a small system gas capacity are operating realities.
Performance of Powered Water Injectors in Arab ‘D’ Reservoir of UMM Shaif Field Offshore Abu Dhabi
Authors: El-Hadidi S. M. , Al-Rubaie J. S. , Allam M. , Fadak A.
Published: December 2007

Power water injection started in Umm Shaif Arab D reservoirs as early as January 1976. Presently, there are more than 15 wells converted from dumpflood to power injection using treated seawater from the Gulf. Water quality specifications in ADMA-OPCO are in line with water quality specifications of other operating companies in the region. A comparison is presented.

Daily injection rates and corresponding wellhead injection pressures are recorded daily using telemetry. Injectivity indices versus time for each power injector were calculated using well performance data and pressure fall-off tests. A deterioration of injectivity indices with time was observed. Reasons for injectivity indices deterioration were investigated and recommended action(s) are presented. One of the wells was backflowed and an assessment of the backflow exercise is presented.
Principles and Applications of a New In-Situ Method for Inspection of Well Casing
Authors: Smith Glenn S.
Published: December 2007

The ETT-C is a recently developed corrosion tool for the in-situ inspection of well casing. Electromagnetic techniques are used to measure casing wall thickness, apparent magnetic permeability, and inside diameter. Previous tools of this type made a single measurement which was dependent on both wall thickness and magnetic permeability. The single measurement technique did not allow the log analyst to differentiate between thickness changes and magnetic permeability variations. The ETT-C system monitors magnetic permeability to obtain an independent wall thickness measurement. A sensitive, non-contact internal diameter measurement has also been added.

A system description explains the ETT-C measurement principles, significance, and processing interaction. Tool applications and interpretation are also discussed. The utility of the additional information provided by the ETT-C is demonstrated with log examples.
Effect of Formation Heterogeneity and Temperature on Alkaline Waterflooding Performance
Authors: Dokla Mahmoud E.
Published: December 2007

The effect of permeability variation on recovery from unconsolidated sand-packs when flooded with alkaline water was studied. The effect of temperature on the process was also considered. Floods were carried out on stratified and heterogeneous sand-packs with permeability ratios up to 7.

Alkaline water results in higher oil recovery from stratified and heterogeneous systems than ordinary water. Maximum recovery occurs when the pH of displacing water is around 10. It is believed that alkaline water results in contact angle values around 90°, which is better for oil movement. Water-oil permeability ratio is affected by type of displacing water and by temperature. Increasing the temperature has the effect of smoothing the differences in oil recovery caused by permeability variation.
Advancements in Drill Stem Testing Through the Use of Annular Pressure Responsive Equipment and Improvements in Open Hole Testing Through Inflatable Packer Systems
Authors: Hortman Norman G. , Callis Cliff G.
Published: December 2007

Many advancements have been forthcoming over the past decade in relation to new techniques in testing of oil and gas reservoirs. Perhaps the most significant advancement over the past decade has been the use of annulus pressure responsive testing tools. We will endeavor in this paper to present a state of the art on all of the various tools including valves, sampling equipment, etc. used in an annulus pressure operated string.

We will give a general run down on the success and failure of these tools which have been used extensively in North Sea and Far East operations. Additionally, we will present conclusive arguments to prove the need for the use of annular pressure responsive tools both on land and in shallow water operations.

The advantage of APR® tools is that they allow opening and closing of the tool to the samples or other operations without rotation or reciprocation of the testing string. This, of course, allows for a much safer operation on non-rigid drilling platforms. The enhanced safety from such an operation also makes this system applicable on land and jack-ups in relatively shallow water where high pressure or H2S environments create unusual safety problems.

Additionally, a general run down on the state of the art will be given in reference to a new inflatable testing packer which has found widespread use. The obvious advantage of an inflation packer is that they require no weight to expand and are more functional in larger washed out holes than conventional weight operated packers. Their use in drill stem testing requires the application of a down hole pump since surface pump pressure cannot be utilized with an empty or partially empty drill pipe.

A new inflation type testing packer system has recently been introduced with excellent success and customer acceptance. We will describe the developmental efforts and more specifically the field experience gained since introducing the system.
Waterflooding Performance and Pressure Analysis of Heterogeneous Reservoirs
Authors: Osman Mohammed E. , Tiab Djebbar
Published: December 2007

This paper presents a study of fluid flow in heterogeneous porous media. The major part presents a modification to the Dykstra-Parsons method to predict waterflooding performance of multi-layered composite reservoirs. The modification takes into account the variations in reservoir properties and dimensions both vertically and horizontally. Two important cases, constant injection rate and constant injection pressure drop, are considered. It was found that waterflooding performance in multi-layered composite linear reservoirs is mainly controlled by the mobility ratio.

The rest of the paper discusses the pressure behavior of a well located in the center of the multi-layered composite reservoir. It was found that changes in fractional flow rates from each layer and pressure behavior are mainly controlled by transmissibility variations from layer to layer and from region to region.
A Practical Approach in Developing a Stabilizing Assembly for Deep Hole Drilling
Authors: Melton Horace B.
Published: December 2007

The deeper a hole is drilled the more important it becomes to control hole changes and maintain hole straightness. Stabilizing assemblies have been accepted as the best method for accomplishing this. Designing an assembly by evaluating formation conditions proves to be a practical method for stabilizer selection and assembly design.
The Role of Seismic Data in Planning Drilling Programs for Ultra Deep Geopressured Tests in the Gulf Coast
Authors: Kozik Harry G.
Published: December 2007

The success of drilling to deep objectives in the Gulf Coast will depend upon the ability to predict accurately pore fluid pressures and formation fracture gradients for each geological formation before it is penetrated.

With proper processing, seismic can provide the driller reasonable data on the aforementioned critical parameters whereby he can set up his casing and drilling programs to reach his objective safely with minimum cost.
Ixtoc No. 1, Blowout and Control Operation
Authors: Lugo Oscar Luis Ulloa , De Leon Ignacio Osorio
Published: December 2007

The Well IXTOC No. 1 was located 94 km Northwest of Ciudad del Carmen, Campeche in the Gulf of Mexico. The drilling objective was to determine the existence of hydrocarbons in carbonate rocks of the paleocene, cretaceous and jurassic formations; the drilling operation was initiated on December 1st, 1978. On June the 3rd at 2:45 hrs., the Well started to flow out of control. This was the beginning of the IXTOC No. 1 blowout which lasted nine months and twenty-two days.

The purpose of this paper is to describe in a summarized form, the well control activities, including: the operations to reduce the flow of the well, the drilling of the directional control wells Ixtoc 1-A and Ixtoc 1-B, the installations used to assist in the operation and the pumping of fluids from the directional Wells to achieve the dynamic control on the Ixtoc No. 1 Well, that brought about the final plug operation.
Pressure Gradient Determination from the Fluid Density Log
Authors: Sarabian A. R.
Published: December 2007

Pressure gradient determination in production and injection wells is essential to obtain information concerning the effects of flow-rate, pipe size, and pressure on each other. This factor is also used to estimate the power and gas injection-rate requirements for lifting the oil in the case of gas-lift operations.

Although the theory and methods for predicting the pressure gradient in the vertical pipe in which gas, oil, and water are flowing have been developed, the majority of techniques require graphical procedures to calculate the pressure gradients which result in the between 10% to 20% errors.

The present method utilizes the fluid density tool to estimate the density of the fluid in the vertical pipe for determining the pressure gradients when two or three phases are encountered. This technique is much shorter than those given in the literature, and does not include any graphical procedure. Furthermore, the pressure profile can be predicted with higher accuracy than those other methods.
Economic Field Development Planning
Authors: Bennett Paul M.
Published: December 2007

Once a field has been discovered and a general method of reservoir exploitation selected, there are many ways to attain the reservoir management goal, but some ways may cost twice as much as others. The purpose of this paper is to discuss the importance of in-depth, overview development planning and to suggest the timing of such reviews. In general, such planning should consider all field development options rather than concentrate on certain phases while ignoring others that may be equally important. The pertinent development options are listed then discussed with examples.
Early Implementation of A Full-Scale Waterflood in The Abo Reef, Terry Co., Tx. - A Case History
Authors: Benton Jerry P. , Maslanka Paul M. , Smith Robert L.
Published: December 2007

The kingdom Abo Reef Field, located in the northwestern portion of Terry County, Texas is a relatively recent discovery along a linear organic bank trend which is intermittently productive from Eddy County, New Mexico to Hockley County, Texas (Fig. 1). Gulf Oil Corporation operates a major portion of the Kingdom Abo Reef Field, thus enabling Gulf to rapidly apply the technology that is highlighted in this paper.

The first part of this paper deals with the history and initial development of the field with the objective of providing a basis for a waterflood project. The emphasis is placed not on the development of new technology, but rather the application of existing technology in characterizing the reservoir to assist in the early recognition of a low primary recovery factor. An analysis of basic data taken during development and early production operations led to the conclusion that primary operations would result in a low primary recovery, which provides the setting for the waterflood feasibility study. The description of the waterflood feasibility study emphasizes the specific methodology employed to predict the waterflood performance. The physical development of the waterflood is discussed which emphasizes both the infill expansion project and the water-injection systems. The paper concludes with a discussion of the present operations and a review of the flood's performance.

Interest in Abo carbonate reservoirs began with the discovery of the Lovington Abo Field in Lea County, New Mexico in 1951. Subsequent discoveries were made in the Empire Abo Field in 1957 and Vacuum Abo Field in 1960 along what is today called the Abo Reef Trend. It is along this geologic trend in Terry County, Texas that the Kingdom Abo Reef Field is located.
Carbon Dioxide Foam Rheology in Porous Media: a CT Scan Study
Authors: Du D. , Zitha P. L. J. , Uijttenhout M. G. H.
Published: December 2007

Carbon Dioxide (CO2) foam has been widely studied in connection with its application in EOR. This paper reports an experimental study concerning CO2 foam propagation in a surfactant saturated Bentheim sandstone core and the subsequent liquid injection with the aid of X-ray Computed Tomography (CT). The experiments were carried out under various system backpressures. It is found that CO2 foam flows in a characteristic front-like manner in the transient stage and the water saturation keeps at relatively high level at the outlet of the porous media due to CO2 solubility and capillary end effect. The subsequent surfactant solution injection shows a significant fingering behavior, accompanied by a low flow resistance over the core. It is also found that CO2 foam flow shows higher liquid saturation near the outlet and lower pressure drops under higher system backpressures. This can be attributed to the solubility of CO2 in the liquid phase. The results indicate the advantage of using foam in EOR process such as water alternating foam (WAF), where foam flow has higher sweep efficiency and stronger mobility control ability compared for instance to WAG. Nevertheless, care should be taken during water injection stage in order not to favour the fingering.
Multiple Application of Image Log Data to EOR Operations in the Cooper Basin, Australia
Authors: Mildren S. , Burgess J. , Meyer J.
Published: December 2007

Reservoir geometry, natural fracture networks and in situ stress directly impact on the planning and implementation of flooding operations. Image logs were acquired from two wells in Field A, the Cooper Basin, with three main objectives in mind: increase confidence on the distribution of oil reservoir sand prior to in-fill drilling; quantify natural fracture populations and assess their possible contribution to production from a tight reservoir, and; quantify the contemporary stress regime and consider its bearing on idealised flow direction.

Tectonic tilt and palaeocurrent indicators were identified in conjunction with natural fractures and in situ stress features from both wells. Palaeocurrent flow directions confirmed a dominant transport direction to the south. However, sediment transport within the Tirrawarra Sandstone reservoir is clearly to the northeast parallel to the strike of the Field A structure. This implies enhanced permeability parallel to this direction due to grain stacking.

Natural fracture density is more enhanced at the crest of the structure than the flanks and the dominant 065°N natural fracture trend is predicted to have greater hydraulic conductivity with respect to the in situ stress field.

The in situ stress field was determined to be strike-slip with σHmax oriented approximately 117°N defining a third permeability enhacement associated with Field A. Without further knowledge of the relative magnitudes of each of these permeability enhancements, it is recognized that EOR patterns planned in an east-west orientation will maximize flooding and sweep efficiency within the Tirrawarra Sandstone oil reservoir.
Utilization of Composition Observation Wells in a West Texas CO2 Pilot Flood
Authors: Henry R. L. , Feather G. L. , Smith L. R. , Fussell D. D.
Published: December 2007

Two composition observation wells were drilled in a tertiary CO2 pilot in the Levelland Field, Hockley County, Texas. The purposes of these wells were to 1) confirm the laboratory determined mechanism of oil displacement from the composition analysis of mobilized fluids; 2) obtain mixing zone length and growth information to improve estimates of CO2 requirements for fieldwide floods; 3) determine relative mobilities of the various banks, and 4) obtain information on CO2-reservoir rock interactions.

Composition observation wells were drilled 15.2m and 44.2m from an injection well and inline with a central producing well. The composition wells were completed in a 10.7m interval of the total 54.9m pay section. Representative reservoir fluid samples were obtained periodically (usually once a week) from these wells through the use of a bottom-hole sampler, and the volumes of the various fluids (gas, oil, and water) collected were measured. The composition of the hydrocarbons was determined by chromatography techniques. This permitted a composition profile of the oil moving zone (CO2-oil mixing zone) to be determined for each of the wells. The ionic concentration in the water was determined by standard mineral analyses.

Composition data confirmed miscible tertiary oil displacement. A small CO2-free oil bank was detected followed by a relatively large oil moving zone which grew with distance traveled from the injection well. The initial analysis of the oil moving zone growth was consistent with a laboratory determined correlation based on first contact miscible fluids. Volumetric data, which are the changes in bottom-hole water-oil ratio with time, indicated more than one zone was swept by the carbon dioxide. Logging observation well data confirmed this conclusion. Bottom-hole pressure data recorded in the composition observation wells showed a cyclic trend with higher pressures occurring during the CO2 injection cycle and lower pressures occurring during the water injection cycle. Preliminary calculations of the total mobility of fluids flowing between the observation wells suggested an in-depth mobility reduction during the CO2 slug process as compared to the pre-CO2 waterflood. Analyses of the water obtained in the sampler indicated CO2 displaces connate water and slowly reacts with the reservoir rock.
Manvel Enhanced Recovery Pilot - Performance Evaluation
Authors: Widmyer Richard H. , Pindell Robert G.
Published: December 2007

A surfactant-polymer pilot flood was conducted in the Manvel Field, Brazoria County, Texas. The chemical system, reservoir matrix and fluid parameters, pilot design and implementation equipment and procedures were described in a previous paper.1 The purpose of this report is to present the test results and conclusions based upon an interpretation of the performance response.

The objectives were to test the effectiveness of a brine-tolerant chemical system in the presence of a high salinity, active water drive where formation preconditioning was not applicable. The relatively high temperature of the 6 m thick, 1646 m deep sandstone reservoir was 75°C. A number of similar reservoirs exist on the Gulf Coast.

As shown in Figure 1, the well array consisted of 2 injection and 3 production wells in a line drive configuration, with 142 m between adjacent wells. The pilot was located in a fault block and aligned with a water drive source from the southwest across the non-sealing Natali Fault. Injection and production rates were optimized at 159 m3/day/injection well and 175 m3/day/production well.1 The total production rate exceeded the injection rates to maximize capture and confinement.
A Computer Model for Comparative Economic Analysis of Enhanced Oil Recovery Projects
Authors: Cronquist Chapman , Secrest E. Leigh , Jones Jack W.
Published: December 2007

A computer model has been developed for comparative analysis of EOR project economics which affords the versatility to analyze economic sensitivities for most injection sequences and economic aspects of several different types of enhanced oil recovery processes.

Input of economic parameters is in terms of constant value dollars for investments and operating costs. Input of project performance is by specifying cumulative fractional oil recovery versus cumulative pore volumes of material injected. Risk can be appraised by input of three such relations, i.e., "expected", "good", and "poor" performance, each of which can be probability-weighted. Conversion to time-rate of recovery is done internally, either through input transmissibility data or user specified pore volume injection rate for each injection stage.

Economic sensitivities to various input parameters are in terms of a new economic parameter, "present value cost per present value barrel", which was developed in the course of this work.

Project performance and economic data from Maraflood projects in Pennsylvania and Illinois were utilized to demonstrate model capability. Economic sensitivities are presented for variation in: barrels per acre-foot recovered, time rate of recovery, cost of chemical slug, cost of polymer, initial investment, and direct operating cost.

The model is intended primarily for investigation of economic sensitivities to parameters like: oil in place at project initiation, recovery efficiency, transmissibility, and material-investment-operating costs. It is not intended for a stand alone evaluation of the feasibility of undertaking a specific project, although it can be used in support of programs designed to do so.
Polymer Augmented Waterflooding at The West Yellow Creek Field Recovery and Cost Experience
Authors: Holstein E. D.
Published: December 2007

My discussion concerns Exxon's experience in operating the West Yellow Creek Field polymer augmented waterflood. I will be discussing the additional recovery benefits of polymer injection, some of our operating experiences and projected costs which affect the economics of the project.
A Type Curve Approach to Reserves for the Big Piney Gas Field
Authors: Hale Brent W.
Published: December 2007

Various methods have been used to define the reserves for the Frontier/Muddy formations of the Big Piney Gas Field. This paper reports the results of a study based on production histories interpreted with constant pressure type curves. Over 80 wells were studied in detail with resulting data used to develop relationships between rate, permeability, and net pay. Using these empirical relationships, reserves for the field were determined. Gas-in-place was calculated for each well as well as effective drainage area and recovery efficiency. Individual well deliverabilities were calculated. A relationship between effective well spacing and recovery was developed.

The results of the study generally agree with previous work. The type curve approach should prove useful in providing details about effective gas-in-place and drainage area. This is not easily obtained from conventional testing. It also provides a link to analyzing newer tight gas wells by showing that type curve solutions are valid over the life of a well.
Greater Green River Basin Stratigraphy as IT Relates to Natural Gas Potential
Authors: Newman Harry E.
Published: December 2007

Major reserves of natural gas remain to be discovered in the Greater Green River Basin of southwestern Wyoming and northwestern Colorado. This basin, occupying approximately 21,000 square miles, includes four sub-basins. These are the Green River Basin proper, west of the Rock Springs Uplift, and the Red Desert, Washakie, and Sand Wash Basins, on the east side of the uplift. Thick sections of Tertiary and Upper Cretaceous rocks exist throughout most parts of the Greater Green River Basin. Drilling depths to penetrate these sections range from relatively shallow depths on the flanks of the individual basins to depths greater than 20,000 ft in certain areas of the Green River Basin proper. The Mesaverde Group, Lewis, Lance and Lower Tertiary Fort Union and Wasatch Formations have significant thick intervals of tight and near tight sandstones containing natural gas. Most of the new discoveries will probably come from stratigraphic traps. Although many of these reservoirs are currently non-commercial, there is a tremendous future potential with improvements in drilling and completion practices. With increased gas prices, new interests in deep drilling have been created.

Five generalized lithofacies maps of the environments of the Upper Cretaceous section of the Greater Green River Basin of Wyoming were constructed to provide information on the productive areas of the stratigraphic section. These maps also indicate the extent of these intervals in the basin, those areas in the basin with the thickest section and some key strand plain trends. This report and the lithofacies maps should provide a good overview of the geology of the Upper Cretaceous and Lower Tertiary stratigraphic section in the Greater Green River Basin of Wyoming and help determine where the most future potential exists for natural gas.
Mobility Control, A New Tool Engineering
Authors: Schurz George F.
Published: December 2007

A new tool has become available to the water flood engineer as a result of recent discoveries in polymer chemistry. It is now possible to treat injection brines with appropriate polymeric materials to reduce the mobility of the brine solution in the formation. This permits the adjustment of the water oil mobility ratio to the most advantageous point for efficient oil recovery.

Standard calculation procedures of reservoir engineering can be applied to estimate maximum recovery improvement through the use of polymer solutions, however, the economic optimum point is not calculable by prior techniques. The ability to predict recovery improvement, however, makes it possible to eliminate fields where mobility control is not required and also to decide on an appropriate value of mobility ratio to use on the field in question.

The equipment used for a mobility-controlled flood is primarily standard oil field equipment. Capital expenditures for such equipment are negligible. The polymers used present no special problems of toxicity or corrosiveness.

INTRODUCTION

Recently announced discoveries in water flooding have yielded new techniques of potentially great benefit to the petroleum industry. It has been shown that certain water soluble polymeric materials may be dissolved in water flood brine to give a flooding medium whose mobility in porous media is greatly reduced. The extent of the mobility reduction may be varied at will over a considerable range depending On the field conditions. Practical reductions of mobility up to twenty fold have been disclosed.

This reduction in mobility 1s important because by properly controlling the mobility ratio between the oil and the displacing phase important improvements in recovery can be achieved thus potentially improving the economics and hence extending the useful range of the water flooding process. The present paper discusses the techniques and apparatus necessary in the field use of such solutions.
Stochastic Model of Fracture Propagation: Initial Results
Authors: Palmer Ian D. , Carroll Herbert B.
Published: December 2007

A model of hydraulic fracture propagation through a medium which contains variations of in-situ stress has been developed. An expanding fracture is divided into a number of sectors, and a stress intensity factor Ki is calculated at each sector tip. Sector expansion is proportional to Ki and radial fluid flow equations are applied to each sector. Although non-rigorous, the model allows estimates of the likely effects that stress variations have on fracture length and bottomhole pressure. Initial results are presented to illustrate such effects: (1) payzone bounded by uniform higher stress zones, (2) payzone bounded by higher stress zones within which are superimposed random stresses (giving the probability of breakout), (3) alternating sandstone/shale layers with fixed shale stress but random sandstone layer stresses (giving the probability of a fracture reaching a desired length). The results are preliminary and refinements to the model will be made.
Lice, Mites, Bedbugs, Fleas, Tumbu Flies: Disease-Causing Agents Preventable through Appropriate Laundry Practices, Sanitation Regimes, and Hygiene
Authors: Balge M. Z. , Krieger G. R.
Published: December 2007

During construction phases of oil and gas development projects, living and working environments can become crowded due to the influx of large numbers of personnel from a variety of different cultures. This paper will present practical measures that can be implemented that will prevent the acquisition and transmission of diseases related to poor housekeeping, laundry and sanitation.

Appropriate cleaning and sanitation of living and work areas can prevent a variety of diseases related to filth and dirty environments. They include:

✵ Scabies (mites) ✵ Pediculus humanus capitis, Pediculus Humanus and Pthirus pubis (Human lice) ✵ Typhus fever, trench fever (body louse) ✵ Scrub typhus (mites) ✵ Plague and typhus (rat fleas) ✵ Myiasis (tumbu fly, bot fly) ✵ Fungal diseases such as ringworm and parasitic worms

These diseases can be transmitted through contact with infested bedding, clothing, linen, toweling, unsanitary bathing facilities, and contact with contaminated soil. Although they are not disease vectors, bedbug infestations can create skin irritations leading to infections.
A Practical Approach to Transient Pressure Behavior
Authors: Mead Homer N.
Published: December 2007

A new concept for transient pressure buildup analysis is developed based upon the following:

A different method for calculating pressure drop in a reservoir and across the skin. Any measured buildup curve is matched (after wellbore and storage effects have died out) with a rectangular hyperbolic equation specific for that buildup. The asymptote to the time axis of the specific hyperbolic equation is final static buildup pressure. The maximum slope of the MDH plot using the calculated points from the rectangular hyperbolic equation is taken to be m. A direct relationship is developed between the buildup time to maximum slope on the calculated MDH plot and the actual distance to the radius of drainage at the time of shutin.

The methods for determining m and the calculated distance to the effective drainage radius at the time of shutin are empirical.