bluuebunny/crossref_metadata_2025 huggingface dataset:
A Deconvolution Method Based on Cumulative Production for Continuously Measured Flowrate and Pressure Data
Authors: Ilk D. , Valkó P. P. , Blasingame T. A.
Published: December 2007

This work presents a new methodology for the analysis of permanent downhole gauge and production data based on the deconvolution of cumulative production and bottomhole pressure measurements.

In this work we show that the cumulative production is a convolution of pressure drop (as if the well were producing at a series of constant flowing bottomhole pressures) and flowrates (as if the well were producing at a constant pressure throughout the production history). We then employ our modified B-spline based deconvolution algorithm which, in this work, is based on constant stepwise pressures. We use analytical integration of the B-splines, weighted least squares and regu-larization to obtain the constant-pressure rate response function and to estimate the initial pressure. The Laplace transformation is not required in this work.

We have validated this approach thoroughly using a synthetic case. We have applied this methodology to various field example cases consisting of both high and low frequency production data. The results indicate that the new method is very efficient in recovering the constant-pressure rate response function in cases where rates are controlled by series of constant flowing bottomhole pressures. We also provide a procedure to check the correlation between pressure and rate measurements by the joint use of two deconvolution methods (SPE 95571 and this work).
Dynamic Rock Types for Generating Reliable and Consistent Saturation Functions for Simulation Models
Authors: Ghedan Shawket G.
Published: December 2007

In reservoir characterization studies, static reservoir rock types, SRRTs, are utilized to guide the modeling of reservoir petrophysical properties in static geological models. However, since the reservoir dynamic properties are not considered in the static rock typing schemes, the SRRTs should not be used - as being practiced now – to guide the distribution of the reservoir multiphase dynamic properties of capillary pressure, Pc, and relative permeability, Kr, curves to the cells of dynamic simulation models.

Considering the rock attributes that goes into any SRRTs scheme and assuming identical interfacial tension between the different reservoir fluids, this paper suggests that the dynamic reservoir rock types, DRRTs, would only be a function of wettability for any SRRT. Thus by imposing wettability on the SRRTs, reservoir engineers should be able to generate the DRRTs, the proper guide for generating and distributing Pc and Kr curves for simulation models.

This technique is applied for building the simulation model of a major carbonate oil reservoir. The gradual change of reservoir wettability from oil wet to water wet dictated the generation of many DRRTs for any SRRT, each defines that SRRT at a different reservoir level between the top and the upper limit of the transition zone.

Available experimental Pc and Kr data, acquired for only few SRRTs, were utilized to develop correlations to determine the saturation and Kr endpoints of the Kr curves. The connate water saturation, Swc, of any DRRT is picked from the Pc curve of the parent SRRT at that DRRT reservoir level. Swc correlated with the residual oil saturation, Sorw. Sorw is in turn used to establish the maximum water Kr point of Krwmax. Oil Kr maximum point, Kromax, is assumed to be 1. Furthermore, the shape of the different Kr curves would be devised by picking the corresponding Corey exponents as they are correlated with wettability for any SRRT. The consistently derived sets of Kr curves helped build a very well initialized and history matched simulation model.
EOR Methods to Enhance Gas Oil Gravity Drainage:Modeling Aspects
Authors: Boerrigter P. M. , Verlaan M. L. , Yang D.
Published: December 2007

Conventional displacement methods such as water flooding do not work effectively in densely fractured reservoirs: due to the high fracture permeability it is not possible to establish significant pressure differentials across oil bearing matrix blocks to drive oil from matrix rock towards producers. In such reservoirs one has to rely on natural mechanisms like capillary imbibition or gravity to recover oil from the matrix reservoir rock. In Middle-East fractured carbonates, the matrix rock is commonly oil-wet or mixed wet and only gravity drainage remains a feasible process. However, permeabilities are usually low, <10 mDarcy, resulting in low gravity drainage production rates with high remaining oil saturation and/or capillary holdup.

EOR techniques such as steam injection and miscible gas injection have the potential to improve GOGD rates and recoveries: –In shallow fractured reservoirs it is possible to inject steam in the fracture system. Steam will condense as long as it contacts cooler matrix rock, resulting in a steam front that develops in a stable way through the fracture system. Heating of the matrix will result in oil expansion, reduction of viscosity, gas drive and stripping effects.–In deeper reservoirs GOGD under miscible conditions becomes an option. Injection gas that is miscible with the oil will result in swelling and viscosity reduction, both increasing oil mobility and therefore improving the GOGD rates. Miscibility further adds the advantages of single-phase flow at high effective relative permeability and reduced interfacial tension, thereby reducing re-imbibition effects and increasing ultimate recovery from inhomogeneous reservoirs.

To assess the benefit of these EOR methods, simulation techniques should be capable of modelling the impact of these processes on GOGD. We present in this paper a general dual permeability method that can handle GOGD as well as different, mutually interacting, processes expected to occur when EOR techniques are applied to fractured reservoirs.
Innovative Pattern Balancing and Waterflood Optimization of a Super Giant Carbonate Mauddud Reservoir, Sabiriyah Field, North Kuwait
Authors: Al-Ajmi Moudi , Baroon Bodoor , Al-Hamer Mohammad , Al-Anzi Ealian , Al-Muwail Majeed , Al-Anzi Hamed
Published: December 2007

Sabiriyah Mauddud (SA MA), a super giant depletion drive oil reservoir in North Kuwait (NK), is undergoing massive development efforts, with a planned enhancement in oil production through phased pattern waterflood. The Phase1 development covers the crestal area of the structure, which is the focus for current development efforts through 12 inverted 9-spot patterns. This paper outlines the successful integration of subsurface, water handling, well surveillance and production operations teams across the NK asset to significantly improve the operating procedure for waterflooding the SA MA reservoir. This effort required a new way of managing this reservoir in NK: a comprehensive approach of balancing voidage with injection, conducting extensive surveillance/analysis within the reservoir to assess the efficacy of various courses of action and, most significantly, adjusting various teams’ "key performance indicators" to align injection and production allowables with sound reservoir management principles.

The health of the waterflood is regularly checked and monitored through revision of production/injection allowable and pattern balancing. An innovative unified information management system was used to monitor voidage replacement ratio (VRR) to provide a basis for pattern balancing. A very extensive surveillance operation provides the data necessary to monitor individual pattern balance and watercut performance, optimize areal sweep efficiency by adjusting injection and production allowables, assist in planning water shutoff operations, and design new completions.

Time lapsed monitoring and the surveillance data indicates the reservoir is relatively well connected. Pattern VRR, pressures, and watercuts were somewhat out of balance prior to engaging in this effort. However, after applying the new management approach, individual waterflood pattern balance is significantly improved and the field-wide VRR is around 1.2.

All of these activities have led to the enhanced understanding of the waterflood behavior and the model updates. Sound reservoir surveillance and waterflood management procedures implemented within a diverse group of teams that have performance goals aligned with "best practice" has resulted in effectively re-balancing this major waterflood. This effective integration of teams retains the flexibility to adjust for an ongoing development of this super giant field. This paper also brings out the case history of waterflood management in a super giant carbonate reservoir and the challenges met during the last seven years since the commissioning of the waterflood in year 2000.
Sensitivity Analysis of Important Parameters Affecting Minimum Miscibility Pressure (MMP) of Nitrogen Injection into Conventional Oil Reservoirs
Authors: Vahidi A. , Zargar Gh.
Published: December 2007

Nitrogen has been found to be a suitable recovery agent for conventional oil with API gravity larger than 35 that provides the reservoir pressure is above the minimum miscibility pressure and the reservoir oil contains a high concentration of intermediate hydrocarbon components. Nitrogen has been found to achieve dynamic miscibility at high pressures. The miscibility obtained by nitrogen injection in light crude oil reservoir is a conditional miscibility, where the fluids are not miscible on first contact, but form two phases, with one of the fluids absorbing components from the other. After sufficient contacts and exchanges of components, at minimum miscible pressure, the system becomes miscible.

The main purpose of this study is to investigate, the effect of temperature, composition of the reservoir fluid and injected gas, on the MMP of nitrogen injection in light oil reservoir by a simulator. The injected gas is pure Nitrogen or a combination of nitrogen with other gas like propane. The effect of varying the percentage of nitrogen and CO2 in the injection gas mixture on MMP has been previously investigated by experiment.

Results of the Simulation have shown that the most important factor to achieve miscibility between nitrogen and reservoir oil is the amount of light and intermediate components in the oil. Increasing the intermediate components and decreasing the methane content decrease the MMP. Nitrogen develops miscibility of oil by the same mechanism as methane (vaporizing gas drive). With sufficient amount of methane in oil reservoir, MMP of nitrogen and methane injection is almost the same but decreasing the methane content causes difference. Studies have shown that injecting nitrogen-propane combination will decrease MMP but combining nitrogen with methane does not have significant effects on the MMP. Result show that MMP of nitrogen increases slightly when temperature decreases.
Development and Application of an Integrated Clustering/Geostatistical Approach for 3D Reservoir Characterization, SACROC Unit, Permian Basin
Authors: González R. J. , Reeves S. R. , Eslinger E. , GarcÍa G.
Published: December 2007

A new 3D reservoir characterization approach is developed that integrates clustering and geostatistical methods. The approach applies clustering methods to well logs and core data for lithology interpretation, reservoir quality characterization, and also for prediction of core porosity and permeability values. Since complete log suites are usually unavailable, clustering is also used to generate synthetic "complete" log suites. In this way, "core" parameter profiles, with high vertical resolution, can be generated for many wells. Geostatistics is then applied to the resulting dataset, and three-dimensional spatial patterns of clusters, porosity, and permeability are utilized to generate reservoir characterizations for flow simulation models.

An advantage of the approach is the application of a soft computing software based on maximum likelihood principles which permits clustering using mixed variables; probabilistic assignment of samples to each multi dimensional cluster; prediction of missing data during the process; lithology estimation of clusters based on a built-in "expert" system; and development of multiple relationships among core and log data for each cluster.

The approach was applied in the platform area of the SACROC Unit (Permian basin), acknowledged as a highly complex carbonate reservoir. In 2004 and 2005, three wells were drilled in this area, were fully cored through the reservoir (~ 800 ft) and porosity and permeability measurements taken on a foot-by-foot basis.. These measurements jointly with modern well logs were utilized to develop models that firstly predict acoustic impedance (product of sonic and density) from only gamma-ray and neutron porosity logs (widely available), and secondly porosity and permeability from these three combined logs. The generalized models, applicable across the platform area, have successfully replicated acoustic impedance where independent data existed for verification, as well as previously acquired core data. This seems to validate the applicability of the new approach in this highly heterogeneous carbonate reservoir.

Unlike seismic inversion and other "data mining" or geostatistical approaches for 3D reservoir characterization, the method described herein can yield, based on the presented example, what appears to be a high resolution result consistent with the known reservoir character.
Detection of Bottom Water Movement Using Well Test
Authors: Ekong Inem S. , Onyekonwu Micheal O.
Published: December 2007

The traditional well testing concept and the mathematical formulations of diffusivity equations for a radial flow system, was used to develop mathematical models for a reservoir-aquifer system incorporating bottom water flow in the vertical direction, considering various reservoir internal boundary and aquifer external boundary conditions. Laplace transformation was utilized in solving the resulting diffusivity equations and inverted to real space using Stefhest Algorithm to obtain dimensionless pressure drop, dimensionless rate and dimensionless cumulative influx with dimensionless time, as a series of constant pressure bottom boundaries. A MS-Visual Basic program was developed to enable quick solutions to be obtained for the Laplace transformation and Stefhest Algorithm expressions at various inner and outer boundary conditions.

The results are presented in graphical and tabulated forms, which are believed to be convenient for engineering use. The developed models were validated with some published work in literature. The pressure and rate transient behaviour of the reservoir-aquifer system as the aquifer bottom water moves in or out of the reservoir was analyzed for the various boundary conditions used in the development of the models.

The developed models can also be used to detect bottom water movement, predict reservoir pressure schedule given water influx rate or cumulative influx and influx rate/cumulative influx can be predicted given reservoir pressure schedule. An example problem using a typical Niger Delta field bottom hole pressure (BHP) survey data was applied with the developed models in the detection/prediction of aquifer bottom water movement.
Economic Implication of Steerable Casing While Drilling
Authors: Busola Oguntuberu Toyin
Published: December 2007

This research aims at proffering a drilling method which would save time and reduce cost while solving borehole problems during the drilling of a directional well.

This was done by performing a case study on two drilling methods. Case one was Conventional Drilling Method (CDM) model and Case two was Steerable Casing while Drilling Method (SCwD) model.

Better drilling technique was recommended based on the conclusion reached from the data acquired through secondary research, comparative analysis preformed on time, cost saving and reduction revenue lost due to open hole associated problems using both methods. SCwD should be adopted for improved application of directional drilling in field development.
Constructed Treatment Wetlands: Innovative Technology for Petroleum Industry
Authors: Eke Paul Emeka , Scholz Miklas , Wallace Scott D.
Published: December 2007

Constructed wetlands are innovative and inexpensive treatment approaches that have the potential of removing organic such as aromatics components [benzene, toluene, ethylbenzene and xylene (BETX)] and inorganic compounds in wastewater from a range of sources. The traditional treatment technologies used by the oil industry such as hydrocyclones, separators, etc. removes only dispersed oil but could not remove aromatics components in dissolved water phase. Despite the effectiveness, environmental friendliness and positive economics of constructed treatment wetlands, the application of this novel wastewater treatment technology is still rare in the petroleum industry.

The study investigates the potential of aromatic hydrocarbon removal in constructed wetland and consequently advancing proper understanding of scientific and optimal operating conditions of constructed treatment wetlands in the petroleum industry. The research focuses on the investigation of the measures to improve the treatment efficiency of contaminants, assessment of the role of the main constructed wetland components and boundary conditions impacting on the operation and treatment performance.

Twelve vertical-flow experimental wetland filters have been designed, constructed using different filter media, and were operated in batch-flow mode to reduce operating cost. The experimental filters were designed to optimize the chemical, physical and microbiological processes naturally occurring within wetlands. Six filters were located indoors, and six outdoors. The outdoor rig simulates natural weather conditions while the indoor rig operates under controlled environmental conditions such as regulated temperature, humidity and light. Findings indicate that the constructed wetlands successfully remove aromatic hydrocarbon (benzene inflow of approximately 1 g L−1) from simulated produced waters with better indoor treatment performances than the rig placed outdoors.

This result suggests that constructed treatment wetland is very attractive, sustainable and innovative technology capable of meeting zero discharge goal in the production, storage, refining and transportation sectors of the oil and gas industry.
Determination of Temperatures for Cementing in Wells Drilled in Deep Water
Authors: Calvert D.G. , Griffin T.J.
Published: December 2007

The American Petroleum Institute (API), Sub-committee 10 (Well Cements) has developed temperature correlations for estimating circulating temperatures for cementing. These correlations use the true vertical depth and a single temperature gradient (computed from the bottomhole static temperature) to make the estimation.

Often wells have temperature transitions meaning that there is a change in temperature gradient below a transition zone. Wells drilled below bodies of water likewise have a temperature transition in the form of the change from water to earthen formations. This can be relatively insignificant, except in the case of large water depths (generally considered to be 1500 ft or more). Such environments are currently being drilled in the U. S. Gulf Coast, Northern Europe, Africa, Brazil, Middle East and Far East. At such water depths, a compounding problem is that the water temperature decreases, approaching the freezing point of water at great depths. It is not uncommon in these areas that the temperature at the mudline or seabed is 40 F or less. Not only is the water temperature low, but formations close below the seafloor are cold also.

This paper describes temperatures in wells drilled in deep water. Computer simulations of wellbore temperatures are presented. Additionally, the simulations show the effects of factors not taken into account by the API correlation. These factors include circulation rate and time, temperature of the injected fluid and sea temperature and currents, to name a few.

Failure to account for the correct temperature can result in greatly extended cement setting times and lead to long delays in continued rig operations. With the rates for deepwater drilling rig operations in the range of $200k-300k per day, any delay in drilling out can increase well costs considerably. Even more importantly, such delays can allow the flow of gas and/or water from shallow overpressured formations, potentially leading to erosion and catastrophic failure of the entire well and surrounding structure, with losses in the hundreds of millions of dollars.

P. 191
A Robust Torque and Drag Analysis Approach for Well Planning and Drillstring Design
Authors: Adewuya Opeyemi A. , Pham Son V.
Published: December 2007

This paper presents a novel torque and drag analysis approach and demonstrates its robustness when used with a versatile computer program. Torque and Drag analysis remains an important evaluation process for assessing drilling feasibility of directional wells, minimizing the occurrence of catastrophic drill string failures and avoiding premature termination of the drilling operation before reaching planned target depth.

From a draft well plan, the drilling engineering analysis is initiated with the development of a representative analytical model using selected entries in a Torque and Drag computer program. Several parameters and instances of evaluation are needed to capture the physical behavior of modeled systems and to produce technically sound results.

The availability of computational tools have not necessarily improved the drilling engineering process or enhance the quality of recommendations without a methodical approach and application of results.

To minimize the iterative steps required to reach an interpretable result, the analytical process as presented in this paper is accelerated with a directed search and a convergence to the determinant drilling variables. The novel approach narrows – the design search domain and tests sensitivities of well-plan characteristics, simulates drilling conditions and applicable drillstring – to the dominant operating factors that determine the boundaries of application.

A record extended reach well (MD/TVD ratio of 2.9) with a lateral displacement of approximately 6,000 ft. was drilled in the GOM using this approach to select tubulars and their position in the well with respect to dogleg severity, inclination and target objectives.
Development of Steerable Ream While Drilling Technology and Its Application in High Angle Wells in GOM
Authors: Cook John , Doster Michael , Dykstra Mark , McDonald Scott
Published: December 2007

Newly developed technology that allows simultaneous reaming and drilling with steerable assemblies has dramatically improved the economics of an extended reach program in the Gulf of Mexico. This paper details the development and application of this unique technology.

The technology development phase comprised laboratory and field tests which examined the dynamic stability and steerability of prototype technology. Laboratory tests confirmed that the pilot stabilization pad (PSP), which is a key feature of the reaming tool, provided enhanced stability in the drilling mode, and expedited the transition from pass-through to drill diameter in the hole opening mode. Field tests proved that the increased length of the reaming system (compared to a bit alone) did not have a negative impact on directional performance of steerable assemblies.

The technology was applied in two intervals in an extended reach well in the Gulf of Mexico. The first interval utilized a 17 in. steerable ream while drilling (SRWD) system with a 9.875 in. roller cone pilot to build inclination at 3 deg/100 ft to 65 deg. The second interval used 9.875 in. SRWD equipment with a 6.5 in. polycrystalline diamond compact (PDC) pilot bit to hold angle near 62 deg over a 8,371 ft interval. Combined, the application of SRWD technology in these intervals reduced drilling time by 17 days, and saved $1,190,000 in drilling cost.

P. 293
Development of a One-Trip ECP Cement Inflation and Stage Cementing System for Open Hole Completions
Authors: Coronado Martin P. , Knebel Mark J.
Published: December 2007

Drilling of horizontal wells continues to increase worldwide. A significant number of these wells are completed with either screen or slotted pipe across the production intervals. Many of these completions require some form of annular isolation to separate different geological zones and to isolate the upper wellbore. As a result, open hole completions are becoming more sophisticated, requiring a systems approach during the installation phase of the operation. Operators are also requiring that these completions be installed with the fewest drill pipe trips as possible to save time and reduce costs.

The new integrated system described in this paper allows the production liner to be run into the wellbore and a liner top hanger system set, multiple external casing packers (ECPs) selectively cement inflated at target locations to provide zonal isolation and then the radius section of the production liner cemented to provide isolation between the liner and upper casing string. Using a newly designed hydraulically-operated cementing valve positioned in the liner above the uppermost ECP, the build section of the liner can be cemented after all the ECPs have been inflated. Using a workstring inside the liner in conjunction with a selective ECP inflation tool, cement can be displaced down the workstring, through the cementing valve, and out into the annulus.

This new open hole completion method has been demonstrated to significantly reduce rig time during the installation phase, and provide the annular zonal isolation required by operators. The system also leaves the production liner free of cement, making subsequent cleanout runs unnecessary.

P. 473
Selective Isolation of Perforated Liners Using Casing Patches: Case Studies from North Sea Operations
Authors: Forbes Charles , Taggart Ian
Published: December 2007

Figures are not available for this paper.

The Weatherford Internal Steel Liner casing patch has been used for many years to mechanically seal off perforations when the completion has been pulled for workover operations.

Recent work has shown that it is possible to carry out this operation with the completion still in place using a Coiled Tubing (CT) or Hydraulic Workover Unit (HWU) to run the Patch. This has offered substantial technical and economic advantages.

The latest development of the tool, a mechanical patch to pass through a 4" restriction and set in a 7" 29ppf liner and will address the majority of North Sea wells.

This Patch system offers an effective mechanical seal option to reduce water production.

P. 497
Optimizing Drilling Strategies in a Tectonic Belt, Pagerungan Field, North of Bali
Authors: Mouton D.E. , Wilton B.S. , Ramos G.G.
Published: December 2007

Initial development drilling programs in the Pagerungan Gas Field were plagued by severe hole problems caused by tectonic stresses and dispersive formations, shallow gas events and logging problems. An optimization study was conducted using a database generated from 14 wells drilled over the past ten years. The results of this study showed that significant improvements in drilling performance could be achieved.

A technique using wellbore stability days as an index was used to account for time-dependent effects of water-base mud systems on dispersive formations. This technique enabled an empirical refinement of a static-elastic wellbore stress model. Additionally, the use of a synthetic-base mud system eliminated the time-dependent effects allowing lower mud densities, casing string reductions, and dramatic increases in rates of penetration. A "batch" drilling/completion schedule accelerated the learning curve effect and optimized the program's logistical efficiency.

By implementing the recommendations of the optimization study, improvements as high as 30% in drilling performance were achieved without compromising safety. As a result, significant financial savings were realized for the program.

P. 559
Turnkey Drilling: Bringing Cost Predictability to a Risky Business
Authors: Baum K.E. , Munson J.R. , Marshall J.A. , Vrooman D.K.
Published: December 2007

Drilling has been and always will be a risky business. Every well is unique and capable of encountering problems far beyond anyone's original expectations. Whether drilling a rank wildcat or the twentieth development well in a field, the risks of our business do not go away. In fact, the risks seem to multiply over time, as wells become more complex due to advances in technology. With this increased operational risk comes additional financial exposure as the cost of all operations has continued to escalate over the recent past.

Performance against predetermined financial goals of an operation is the most universally accepted way to evaluate the success or failure of a project. Turnkey is the only drilling alternative which can cap financial exposure and in the process offer operators the requisite flexibility to conduct their business and manage their resources in a more efficient manner. It is this capability to fix costs, and shift drilling risk that is inking turnkey an increasingly more attractive alternative to operating companies of every size. Turnkey is no longer just a drilling decision; but has become, more importantly, a business decision.

P. 593
Rejuvenating Engineering Students Interest in the Oil Business
Authors: Smith Jack , Warren Diane
Published: December 2007

The downturn of the oil business in the mid 80's and the often heard negative news relating to environmental issues has resulted in a reluctance of present day engineering students to enter this business. This has a dramatic impact on our industry's ability to design and produce new products and to advance the technologies. This paper discusses a four step approach to add technical people to the work force and encourage engineering students to consider careers in the oil business.

These four steps are: Hiring engineering students to work part time as drafters, lab technicians and engineering clerks.Participating in university engineering Co-op programs.Sponsoring engineering student design projects.Using university faculty members as consultants to help on technical problems.

The positive contributions received from these activities and comments and projections on the long term objectives are discussed.
Well Examination – Self Regulation in a Goal Setting Environment
Authors: King Gregory , Dobson Donald
Published: December 2007

Safety in the offshore oil and gas industry in the UK is now enforced through a system of Goal Setting regulations which require companies to set standards and then demonstrate how these are achieved. Within this system the safety of wells and well work is controlled by a requirement for Operators to develop and apply Well Examination Schemes where work programmes are reviewed by Independent and Competent examiners. The paper describes the previous scheme based upon explicit Government approval; the relevant elements of the Goal Setting environment; and how Well Examination Schemes have been developed, how they operate, and the impact of Well Examination for companies working in the UK.
Minimising Down Hole Mud Losses
Authors: Rojas J.C. , Bern P.A. , Fitzgerald B.L. , Modi S. , Bezant P.N.
Published: December 2007

The application of particle sealing technology, field monitoring techniques and improved operational practices has been used to minimise downhole lost circulation while drilling extended-reach wells. These techniques have been applied at the Wytch Farm Development in Southern England and in the Pompano Development in the Gulf of Mexico. Using particle sealing technology, losses were reduced from an average 5,000 bbls of low toxicity mineral oil to zero while drilling the 8" section in offset Wytch Farm wells M-07, M-09 and down hole synthetic mud looses were significantly reduced on Pompano A-l8. Pressure While Drilling (PWD) data have contributed to the improved understanding of how changes in downhole pressure influence lost circulation.

P. 871
Stimulation of Tight Carbonate Reservoirs Using Acid-in-Diesel Emulsions: Field Application
Authors: Al-Anazi H.A. , Nasr-El-Din H.A. , Mohamed S.K.
Published: December 2007

An oil producing well (Well-A) in a carbonate reservoir was dead due to severe formation damage. The well was acidized by regular 15 wt% HCl, but remained dead. A thorough experimental study was conducted to evaluate using acid-in- diesel emulsions, 70 vol% HCl (15 wt%):30 vol% diesel, to stimulate this well which had several tight zones.

Experimental results indicated that the acid-in-diesel emulsion was a viscous and non-Newtonian fluid. The thermal stability of the acid decreased as temperature was increased. The stability of emulsified acid also decreased in the presence of reservoir rock. The emulsified acid was found to be compatible with native crude oil and acid additives, except mutual solvents and demulsifiers. The reactivity of the emulsified acid with reservoir rock was slower than that of the 15 wt% HCl by a factor of 45 at 24 C. The reaction rate of the emulsified acid increased as temperature was increased.

Coreflood results showed that the emulsified acid formed deep wormholes in tight carbonate cores (< 50 md). At the same acid volume and flow rate, the emulsified acid penetrated deeper into the core compared to the regular acid which caused face dissolution. Permeability ratio (final/initial) of reservoir cores exponentially increased with the acid injection rate. The size and number of the wormholes depended on the acid injection rate.

The acid-in-diesel was successfully applied in Well-A using a coiled tubing unit, whereby the well productivity has been increased by several orders of magnitude. After the treatment, a flowmeter test indicated that the percentage production of tight zones has increased by a factor of 2.

P. 9
A Systematic Study of Iron Control Chemicals Used During Well Stimulation
Authors: Taylor K. C. , Nasr-El-Din H. A. , Al-Alawi M. J.
Published: December 2007

A new type of experimental procedure was used to study iron control chemicals (citric acid, nitrilotriacetic acid and acetic acid) in acidizing treatments at temperatures from 25 to 95°C. This procedure gives plots of iron in solution versus equilibrium pH, while previous work has generally studied iron concentration in completely spent acid solutions. Hydrochloric acid concentrations of 7.5 to 28 wt%, sodium chloride concentrations of 0 to 5 wt%, and iron (III) concentrations from 1,000 to 10,000 ppm were examined with varying concentrations of commonly used iron control chemicals. A systematic study of this kind has not previously been reported in the literature. The following new results were found: Iron (III) hydroxide precipitated from spent acid at much lower values of pH than is generally believed in the literature. The general belief is that iron (III) hydroxide precipitation begins at a pH of about 2.2 and is complete at a pH of 3.3. From experimental results, precipitation begins at pH values of about 1 and is nearly complete by pH 2 at 25 C.As the temperature was increased, iron (III) became significantly less soluble in the spent acid. This means that iron (III) hydroxide precipitation is potentially more damaging to the formation than generally believed.Time-dependent iron precipitation can occur in the absence of iron control chemicals.Time-dependent precipitation of ferric/calcium complexes with nitrilotriacetic acid (NTA) and citric acid was found. In partially spent acid, precipitation of previously unreported complexes containing iron/calcium/chelating agent in a 1/1/1 mole ratio was observed. This behavior is important because of potential formation damage during the acidizing treatment itself, or during shut-in of the well after stimulation.Synergism with citric acid/acetic acid mixtures was found. These two iron control chemicals were able to prevent iron precipitation better in combination than individually.
On-site Evaluation of Acidizing Treatment of a Gas Reservoir
Authors: Zhu D. , Hill A. D. , da Motta E. P.
Published: December 2007

Real-time monitoring (on-site evaluation) of acid treatments for oil reservoirs has been developed and applied in the field successfully.1,2,3 The technique uses the transient flow equation to estimate the skin factor evolution during the treatment, in order to evaluate and enhance the effectiveness of stimulation and diversion. The equation used in the real- time monitoring model assumes that the reservoir fluid is single-phase and slightly compressible. This approach has worked well in monitoring skin factor change during acidizing of oil wells; however, when acidizing a gas well, injection of liquidphase acid strongly affects the apparent skin factor because the estimated skin factor depends on the viscosity difference between the reservoir fluid and the injected fluid. The skin factor calculated by the single-phase oil model is wrong if the viscosity contrast is significant. This paper presents a new model to estimate the apparent skin factor for gas reservoirs during acidizing treatments. The model introduces a viscous skin factor to handle the effect of the viscosity difference between the injected fluid and the reservoir fluid on the pressure response. By subtracting the viscous skin factor, which can be calculated as a function of injected acid volume, from the total skin factor obtained from the rate and pressure recorded during the treatment, the true damage skin during an acid treatment is obtained.

Field examples from Brazil show that the real-time monitoring model for acidizing treatments for gas reservoirs has been used to predict the evolving damage skin factor successfully. The examples presented in this paper show that without accounting for the viscous skin effect, the apparent skin factor for the wells rose during the treatment, which could lead to an incorrect interpretation that the treatments were ineffective. However, when the viscous skin was subtracted from the total apparent skin factor, it was seen that the damage skin was decreasing throughout the treatments, as desired. The production data for the wells before and after acidizing confirmed the predicted skin factor behavior by the new model.
The Effect of Near-Wellbore Fracture Geometry on Fracture Execution and Post-Treatment Production of Deviated and Horizontal Wells
Authors: Chen Z. , Economides M.J.
Published: December 2007

The near-wellbore fracture geometry is important to hydraulic fracture execution and the subsequent post- treatment well performance. A fracture from an arbitrarily-oriented well "cuts" the wellbore at an angle and this limits the communication between the wellbore and reservoir. The stress concentration around the wellbore further complicates the near-wellbore fracture geometry. The fracture width at the wellbore can be much smaller than the maximum width, or it may even close when the fracturing pressure decreases below some critical value. The limited communication path may cause a "screenout" during fracture execution or large reduction in the subsequent production because of choked fracture effects. This paper first discusses fracturing conditions for an optimal communication path between the wellbore and the reservoir. The near-wellbore fracture geometry is then determined. The effects of this fracture geometry on fracture execution and production are discussed. Critical fracturing pressures are also calculated for different wellbore orientations and in-situ principal stress magnitudes. Guidelines are provided to enhance the success of fracturing treatments.

P. 75
The Effect of Frac-Fluid Density on Hydraulic Fracture Growth Direction and Width
Authors: Deeg Wolfgang F.J.
Published: December 2007

In the absence of significant formation-stress contrasts between adjacentzones, the frac-fluid density will determine the preferred growth direction of a vertical hydraulic fracture. A vertical hydraulic fracture will grow in aradial or penny-shaped manner if the frac-fluid density is approximately equal to the gradient of the least principal formation stress. Upward growth is favored if the formation-stress gradient exceeds the frac-fluid density.

Even in the presence of significant stress barriers, frac-fluid density may influence the fracture-growth direction within the pay zone and after the hydraulic fracture has penetrated into the barrier layers.

This paper presents a closed-form solution to rapidly assess the effect of treatment fluid density and proppant loading on hydraulic fracture growth direction and width under a given formation-stress state. This solution was used to:

Explain the apparent lack of downward growth in specific hydraulic fracture stimulation treatments

Confirm that large treatment intervals can be successfully stimulated with one treatment

Determine where a horizontal well should be located within the pay zone to maximize coverage by subsequent fracture treatments

These solutions have been successfully used to answer questions such as:

P. 91
Enhancing Fracture Conductivity Through Surface Modification of Proppant
Authors: Nguyen Phillip D. , Weaver Jim D. , Dewprashad Brahmadeo T. , Parker Mark A. , Terracina John M.
Published: December 2007

Society of Petroleum Engineers

A new liquid surface-modification system has been developed for coating proppant, dramatically increasing its surface friction and allowing it to interact instantaneously with surrounding particulates. High surface friction between the coated proppant grains allows them to withstand high flow rate, minimizing their flowback potential after fracture-stimulation treatments.

According to field results, when this surface-modification material was used as a flowback-control agent after conventional fracturing treatments, it permitted more aggressive flowback procedures. This treatment did not impair conductivity, and in fact, increased proppant conductivity at closure stresses below 4,000 psi. Better vertical proppant distribution occurred in experiments that demonstrated increased hindered settling of proppant resulting from this surface modification. Fines that already existed within the proppant, fines generated from the formation, or fines derived from crushed proppant upon fracture closure all adhered to the treated proppant, which inhibited them from migrating and blocking the pore throats of the proppant pack. This unique coating technology further enhanced conductivity by improving frac-gel breaker action in certain fluids. This behavior results in faster, more effective well cleanup after stimulation.

P. 101
A New Model of Acid Fracure Conductivity Based on Deformation of Surface Asperities
Authors: Gong M. , Lacote S. , Hill A.D.
Published: December 2007

A New Model of Acid Fracture Conductivity Based on Deformation of Surface Asperities

Acid fracture conductivity is affected by the aperture and contact area of the fracture under closure stress. This, in turn, depends on the surface asperities created by the acidizing process and the mechanical strength of these asperities. Acid contact time, acid leakoff, rock mechanical properties, and formation heterogeneity all affect the creation of hydraulic conductivity of an acid fracture.

We have conducted a systematic experimental study to investigate the mechanisms of the creation of hydraulic conductivity in acid fractures, including characterization of the surface roughness created by acid etching, investigation of the damage to the rock compressive strength by acid, and measurement of hydraulic conductivity under closure stress. Experimental data show that longer acid contact results in rougher fracture surfaces and, in turn, higher hydraulic conductivity. However, acidizing also reduces the rock compressive strength causing the surface asperities to easily deform under stress.

Based on our experimental results, a new fracture deformation model was derived which considers both the surface roughness and the rock mechanical properties. The fracture closure under stress is modeled as plastic deformation of asperities. Finally, a cubic law is used to calculate the fracture conductivity. The prediction of acid fracture conductivity using this model with appropriate parameters shows good agreement with the experimental data.

P. 133
Sand Control Completion Design, Installation and Performance of High Rate Gas Wells in the Jupiter Field
Authors: Burton Robert C. , Boggan Stuart A.
Published: December 2007

Robert C. Burton and Stuart A. Boggan, Conoco

This paper provides a review of sand control completion design, installation and subsequent well performance in the Jupiter Field.

The paper reviews formation failure predictions used to assess the need for sand control and discusses the completion designs selected to prevent sand production in a series of high rate gas wells. Completion installation, consisting of running pre-packed screens into the drilled hole, wellbore clean-up and initial well testing is also discussed.

A review of long term sand control effectiveness and completion pressure loss data for these wells is also presented.

P. 149
Case History in Achieving High Rate Producers in Sub Sea Gravel Packed Completions
Authors: Myers Larry G. , Humphreys Neil , Kaminski Henry P. , Bouwaked Elias , Robertson David
Published: December 2007

The Zafiro Field, offshore Equatorial Guinea, was developed as a fast track project with production coming onstream in August, 1996 to an FPSO, less than two years from the field discovery. Downhole gauges with surface readout on the FPSO gave continual monitoring of well performance during early production from the field. These subsea wells, which required sand control, were targeted to produce at rates of 8000 bopd. Early wells made this target with Productivity Indices (PI's) of 6 to 33 bopd/psi. However the data also showed high post completion skin damage when compared to skins measured immediately after TCP operations. This real time data allowed continual improvements to be made in completion designs. This paper is a case history of these design changes which more than doubled PI's, yielding producers capable of 14,000 bopd. Design changes included a move to openhole completions where possible, new screen configurations, fluid studies for optimizing gelled fluids to transport sand in high angle and horizontal openhole completions, filter cake removal in openhole completions, and acid stimulation.

P. 159
New Chemistry and Improved Placement Practices Enhance Resin Consolidation: Case Histories From the Gulf of Mexico
Authors: Parlar M. , Ali S.A. , Hoss R. , Wagner D.J. , King L. , Zeiler C. , Thomas R.
Published: December 2007

Resin consolidation has been used as a sand control method since the early 1940s, most widely between 1960 and 1970, with varying degrees of success. Although, in recent years, the total number of resin consolidation treatments has been quite low compared to Frac-Pack, High Rate Water Pack, and Conventional Gravel Pack treatments, interest in resin treatments has been steadily increasing because resins offer a screenless alternative for sand control completions, making them especially suitable for thru-tubing recompletions.

The success of resin consolidation treatments depends strongly on chemistry of the fluids used in each stage of the treatment (addressing microscopic level failure modes) as well as physics of fluid placement (placement practices to avoid viscous and gravitational instabilities and placement methods to minimize the effects of permeability variations for uniform treatment, both addressing macroscopic level failure modes).

In this paper, we present the new chemistry and improved placement practices based on the lessons taken from past experiences and address the failure mechanisms identified in the literature. We also present a set of recommended procedures and guidelines for field application, and lab test results for retained permeability and compressive strength of resin consolidated sand packs. Finally, we present 5 case histories with furan resin system from the Gulf of Mexico as well as statistical information from a total of 25 treatments.

P. 179