bluuebunny/crossref_metadata_2025 huggingface dataset:
New, Rigorous Material Balance Equation for Gas Flow in a Compressible Formation With Residual Fluid Saturation
Authors: Rahman N. M. A. , Anderson D. M. , Mattar L.
Published: December 2007

Modern computing power has enabled very high accuracy and efficiency in complex calculations. Thus, it follows that reservoir engineering formulations need not be approximate solutions, as was sometimes historically the case. Being one of the most widely used techniques in reservoir engineering, the material balance equation (MBE) for gas is an excellent example of this. The MBE is used not only for estimating the original gas-in-place (OGIP), but also for calculating the decline in average reservoir pressure with depletion. In the majority of cases, the conventional p/Z formulation of the gas material balance is satisfactory. However, certain circumstances, which are sometimes unpredictable, demand formulations with greater accuracy. Although modifications to the standard approach have been presented, to the authors’ knowledge, there is no published gas material balance formulation that is completely rigorous. This study presents a new, rigorous MBE for gas flow in the presence of a compressible formation and residual fluid saturation. Examples will be presented to highlight the capabilities of the new MBE.
Using Reservoir Modeling To Evaluate Stimulation Effectiveness in Multilayered "Tight" Gas Reservoirs: A Case History in the Pinedale Anticline Area
Authors: Schubarth S. K. , Spivey J. P. , Huckabee P. T.
Published: December 2007

Low permeability, or "tight", gas reservoirs are being developed at an ever increasing rate in the U.S. The amazing increase in activity in the Rocky Mountain region over the past decade is a testament to this. Currently, there are several "tight" gas plays in the U.S. that involve the commingling of multiple intervals in order to gain economic viability. The Pinedale Anticline of southwestern Wyoming is one of these areas. The Pinedale Anticline completions pose a particularly complex problem when attempting to evaluate the "best" method of stimulation because as many as twenty-two separate stimulation treatments are placed in up to 70 discrete sand intervals over a gross interval up to 6,000 feet thick. Evaluations are further complicated by variation in permeability exceeding two orders of magnitude and pore pressures increasing from 0.44 psi/ft to 0.83 psi/ft.

The analysis of "tight" gas reservoirs has been the topic of many SPE papers over the past twenty years. Several have presented data indicating the broadness of the permeability distribution which may be encountered when developing these reservoirs1,2,3. The broadness of the permeability distribution, often over two orders of magnitude in breadth, poses a statistical problem when trying to simply compare production response of one set of data to another in a given field. We will quantify the significance of this and present statistical evaluations documenting the probability of obtaining two similar data sets with respect to permeability when broad distributions exist. We then compare the size of the sample set necessary to quantify stimulation effectiveness using production alone with the sample size required when using reservoir simulation.

The reservoir simulation analysis presented in the paper demonstrates a process for use in multiple layered reservoirs for evaluating stimulation effectiveness. The process requires significantly fewer field tests than if production rates were used alone. Multiple production logs were utilized over several producing months in selected wells and are crucial to the production history match process. A wide variety of proppant products are investigated and compared to expected performance from published specifications. This paper will aid engineers working in multi-layered reservoirs understand the complexity of the evaluation process and give them a process for evaluating stimulation effectiveness in their reservoirs.
Quantifying Uncertainty in Original-Gas-in-Place Estimates With Bayesian Integration of Volumetric and Material Balance Analyses
Authors: Aprilia A. W. , Li Z. , McVay D. A. , Lee W. J.
Published: December 2007

Accuracy in hydrocarbon reserves estimates affects virtually every phase of the oil and gas business. Unfortunately, reserves estimates are uncertain, since perfect information is seldom available from the reservoir, and uncertainty can complicate the decision-making process. Managers have to make many important decisions early (e.g., facilities expansions, development drilling, etc.) without reliable knowledge of reserves. Thus, it is probably more important to quantify reserves uncertainty early than any other time in the life of a reservoir.

Reserves are closely related to original hydrocarbons in place (OHIP). Two methods for estimating OHIP are volumetric and material balance methods. The volumetric method is convenient to calculate OHIP during the early development period, while the material balance method can be used later, after some performance data, particularly pressure and production information, are available. Both methods may have substantial uncertainty.

In this paper, we present a methodology that uses a Bayesian approach to quantify the uncertainty of original gas in place (G), aquifer productivity index (J), and the volume of the aquifer (Wi) by combining volumetric and material balance analyses in a water-driven gas reservoir.

The results show that we potentially have large uncertainty in OGIP estimates when we consider only volumetric analyses or only material balance analyses. However, by combining the results from both analyses, the uncertainty can be reduced. This reduction in uncertainty should lead to better management decisions in many cases.
Simulation-Based Technology for Rapid Assessment of Redevelopment Potential in Stripper-Gas-Well Fields—Technology Advances and Validation in the Garden Plains Field, Western Canada Sedimentary Basin
Authors: Cheng Y. , McVay D. A. , Wang J. , Ayers W. B.
Published: December 2007

It is often difficult to quantify the redevelopment potential of marginal oil and gas fields due to a wide range of depositional environments, variability in reservoir properties, large numbers of wells, and limited reservoir information. With traditional simulation methods, evaluation of infill potential for these fields is time consuming, labor intensive and frequently cost-prohibitive. Without adequate assessment technology, some unprofitable infill campaigns may be initiated while other promising infill campaigns may be terminated prematurely due to disappointing early results.

In this study, we developed a simulation-based regression technique to assess infill drilling potential in stripper gas well fields. With limited, basic reservoir information, this technique first estimates the spatial distribution of subsurface reservoir properties by rapid history matching of well production data. We implemented a sequential regression algorithm to estimate not only the permeability distribution, but also, the pore volume distribution from available flow rate measurements. Future production is forecast and infill drilling potential is determined using the estimated permeability and pore volume distributions. Because the method employs an approximate reservoir description, it identifies regions of the field with promising infill potential rather than individual infill well locations.

The proposed technique provides rapid, reliable and cost-effective assessment of redevelopment potential in stripper gas well fields. In the paper we first validate our approach using synthetic reservoir data. We then apply the approach to the Second White Specks formation, Garden Plains field, Western Canada Sedimentary Basin. Prediction of infill potential in this gas field, which has more than 700 wells, demonstrates the power and utility of the proposed technique.
The Tools, Techniques, and Advantages Involved in Combining Compression and Plunger Lift in Low-Rate Gas Wells
Authors: Schmitz R. A. , Steele G. D.
Published: December 2007

Plunger lift and compression are two common methods of dealing with liquid loading issues in natural gas wells. However, as the average productivity of the gas wells in the Western Canadian Sedimentary Basin continues to decline, these methods on their own are no longer sufficient for many wells. However, plunger lift combined with compression, using newly-developed and innovative tools and techniques, can provide a solution for many low-rate wells that could not otherwise be produced cost-effectively.
Quasinatural Consolidation of Poorly Consolidated Oilfield Reservoirs
Authors: Larsen T. , Lioliou M. , Josang L. O. , Ostvold T.
Published: December 2007

A new method to prevent sand permeation from unconsolidated or poorly consolidated reservoir formations has been developed. The Quasi Natural Consolidation (QNC)-method involves a controlled in situ precipitation of calcium carbonate scale on sand grains. Experiments show that calcium carbonate forms bridges between sand grains and strengthens the unconsolidated sand pack. The QNC-solution contains Ca2+, urea and urease. When this single-phase solution is injected into the sand pack, calcium carbonate precipitates at a rate which is dependent on the urease concentration and temperature. A series of batch experiments have been carried out in order to establish the optimum solution chemistry/composition for sand consolidation. Consolidation experiments have shown that this method is applicable in the temperature range from 25 °C to at least 65 °C. An untreated sand pack collapsed at a water flow velocity of < 0.01 cm/s (Q/Atot). However, after two QNC-injections at either 25, 50 or 60 °C the sand packs could withstand a water flow velocity >0.38 cm/s without producing sand. The permeability dropped about 25% from the initial ~10 Darcy. Uniaxial strength tests showed that up to 10.56 MPa could be obtained after four injections. Consolidation was obtained also with presence of oil in the sand pack, although with a somewhat reduced efficacy of the treatment. Permeability measurements indicate that the relative water permeability is reduced more than the relative oil permeability after treatment.
Use of Silicate-Based Drilling Fluids To Mitigate Metal Corrosion
Authors: McDonald M. , Barr K. , Dubberley S. R. , Wadsworth G.
Published: December 2007

Since the re-introduction of silicate-based drilling fluids in the mid-1990's, there have been numerous papers written on the inhibitive and environmental properties of sodium and potassium silicate. While it is generally accepted that potassium or sodium based silicate drilling fluids will help mitigate metal corrosion, there appears to be very little written on the subject. With increasing steel prices and competition for drill pipe, operators are becoming more aware of the cost associated with metal corrosion.

This paper discusses the chemistry of sodium and potassium silicate as it relates to the protection of metals against corrosion. Aside from providing an alkaline environment, silicate is shown to deposit a protective film on various metal surfaces. Drill string corrosion coupons were used to gauge the amount of wear and corrosion while running potassium silicate-based drilling fluids in Western Canada. Gravimetric analysis confirmed that the rate of metal corrosion was minimal under a variety of drilling conditions.
Downhole Integrity Management in October Field, Gulf of Suez, Egypt
Authors: Ramadan Nasr , Rocha George , Michel Charlie , Hey Michael James
Published: December 2007

The paper discusses historical data related to downhole scaling, corrosion and surveillance methods to identify affected wells. Efforts to minimize production impact due to increased corrosion seen late in the field life along with longer term corrosion mitigation efforts are also reviewed. Examples of how tubing was originally protected by thin film scale accumulation and emulsion flow during early field life production are also presented. Increasing October's completion corrosion manageability is a key challenge facing the field. Addressing issues related to predicting future well failures and their associated production loss impact rig scheduling and procurement of expensive long-lead time completion material (Cr 13%).

The approved plan is to repair six wells per year over three years considering known well problems, remaining reserves, materials and rig availability. In early 2005, six well's were worked over and visual inspection of retrieved tubing showed an excellent match with caliper log data. The most severe corrosion is typically deep in the well and is related to high CO2 partial pressures. Corrosion risk to the casing has also been identified as potential issue and wall thickness assessments have been performed on some workovers. The paper reviews these items in greater detail and proposes forward plans for the remaining life of field.
Laboratory and Field Prediction of Sulfate Scaling Damage
Authors: Bedrikovetsky P. G. , Mackay E. , Monteiro R. P. , Gladstone P. M. , Rosário F. F.
Published: December 2007

The BaSO4 scaling is a chronicle disaster in waterflood projects with incompatible injected and formation waters. This is usually due to precipitation of barium sulphate from the mixture of both waters and consequent permeability reduction resulting in well productivity decrease.

The sulphate scaling damage system contains two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipitation.

Previous work has derived analytical-model-based method for determination of kinetics coefficient from laboratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of formation damage coefficient from pressure drop measurements during coreflood.

The proposed method can be extended for axi-symmetric flow around the well allowing calculation of both sulphate scaling damage coefficients from field data on barium concentration in produced water and well productivity decline.

We treat several laboratory test data and field data, and obtain values of two sulphate scaling damage parameters. The values of kinetics and formation damage coefficients as obtained from either laboratory or field data vary in the same range intervals. It validates the proposed mathematical model for sulphate scaling damage and the analytical-model-based method "from lab to wells".
Subsidence-Induced Casing Dogleg (SICDog) Remediation With an Innovative Hybrid Milling System
Authors: Winston D. S. , Sullivan M. , Finch R. C. , Fulcher R.
Published: December 2007

Subsidence Induced Casing Doglegs (SICDogs) occur in many oil reservoirs worldwide. Doglegging, at a minimum, leads to reduced mean time between failures of rod pumped wells. SICDog remediation techniques in the past have had limited success and are relatively expensive procedures. Most of these techniques have used various rotating mill assemblies and different strengths, sizes and connections of drill pipe. Some techniques have been extreme, such as destroying the dogleg with explosives. A multiphase, risk-sharing, team effort over four years between Aera Energy LLC and Weatherford International Ltd led to the development by Weatherford of a hybrid broaching/milling tool. This hybrid milling system reliably and quickly remediates multiple doglegs in a single well bore. Seven Diatomite reservoir producers in the South Belridge Oil Field, Kern County, California were repaired and successfully returned to production in the latest four well phase. The work was routine in nature, requiring no special or extraordinary services. In this paper, we will discuss the geometry of SICDogs and the challenges they pose to rotational milling. Other topics will include the evolution of the hybrid tool from experiences in this and other projects, operational concerns such as well control and repair options of the remediated SICDog. Lessons learned during the evolution of this technique will be discussed at length.
Real-Time Monitoring of Acid Stimulation Utilizing a Fiber-Optic DTS System
Authors: Clanton R. W. , Haney J. A. , Pruett R. , Wahl C. L. , Goiffon J. J. , Gualtieri D.
Published: December 2007

This paper discusses a unique system that combines a fiber-optic distributed temperature system (DTS) to measure the distributed temperature across the entire wellbore and a molecular telemetry transmission system that provides a single-point determination of bottomhole pressure. The system has been used to perform real-time downhole monitoring of multi-stage acid-stimulation treatments performed on wells that contain multiple non-isolated pay intervals. The fiber-optic for the DTS is contained inside a length of capillary tubing, which is placed concentrically inside a larger size capillary tubing. The created annulus between these two strings of capillary comprises the molecular transmission system for determining the bottomhole pressure.

Real-time-distributed temperature data and single-point bottomhole pressure data are provided on location. In the case history presented, the temperature profile across the multiple pay intervals yielded valuable information for identifying which zones were "taking" the acid, allocating how much acid these zones were taking (relative to one another), and identifying the zones not taking acid. This allowed on-the-fly changes to be made on-site in real-time regarding the make-up of the acid treatment, the pumping rates, and when and where to apply diversion processes.

This system enabled the operator to continuously monitor the wellbore temperature across the interval that was being stimulated as well as from a single-point bottomhole pressure below the lowest perforation. In this case, the system was deployed inside the work string used for the acid stimulation, but the system can also be permanently deployed.

The nominal ratings for this monitoring system are 250°C and 10,000-psi. This allows the system to be applied in a large number of wells, either onshore or offshore. Furthermore, there are no downhole electronics and no moving parts, making the system extremely well suited for harsh environments.
Tahiti: Development Strategy Assessment Using Design of Experiments and Response Surface Methods
Authors: Carreras P. E. , Turner S. E. , Wilkinson G. T.
Published: December 2007

Tahiti field in deepwater Gulf of Mexico is a three-way anticlinal structure trapped against salt, with primary hydrocarbon-bearing turbidite sands ranging from 24,000 to 27,000 ft TVD. The discovery well was drilled in 2002, and two appraisal wells were drilled soon afterwards. Due to significant uncertainties remaining after appraisal, probabilistic methods were used to assess development alternatives.

In this study the classical experimental design method was applied and reasonable P10, P50 and P90 reservoir simulation models were designed. Next, we looked upon the development plan by performing a second round of design of experiment runs with uncontrollable uncertainties and decisions as factors. The goal was to validate that the previously selected models reasonably represented P10, P50 and P90 oil recoveries and net present value after including decisions in the design. The validation worked out properly reinforcing the confidence in the model selection. Finally, the polynomial response models were used to explore multiple scenarios by varying decisions across the whole range of uncontrollable uncertainties.

The proposed workflow enhances the use of experimental design by combining the technique with response surface methods and rational engineering judgment. The approach is recommended for the evaluation of greenfields when a new perspective of the economic analysis of project decisions is desired.
Analytical Model for Vertical Oil/Water Displacement Under Combined Viscous, Capillary, and Gravity Effects
Authors: Rosado-Vázquez F. J. , Rangel-German E. R. , Rodriguez-de la Garza F.
Published: December 2007

A mathematical model for water injection in vertical porous media initially saturated with oil and water is presented. The mathematical formulation takes the form of a nonlinear convection-diffusion equation. Its contribution comes from consideration of the three chief forces (viscous, capillary and gravity) in oil recovery processes. The model is general in that it can use any shape for relative permeability and capillary pressure functions, and it is developed to allow analysis of these forces individually or in a combined manner.

By using Corey-type functions for relative permeability, logarithmic functions for capillary pressure, and Peclet and Gravity dimensionless numbers, the flow equation is written in a dimensionless form.

In order to represent the physics of the oil-water displacement more accurately, variable saturation-dependent coefficients for the diffusive (capillary) and convection (viscous and gravity) terms were used. Thus, a nonlinear equation is obtained. A numerical model based on the finite-difference formulation with a fully implicit scheme was implemented to obtain the solution to this equation. The analytic solution for the diffusion-convection equation for the semi-infinite problem published elsewhere and the well-known Buckley-Leverett solution were used to validate the numerical algorithm.

The numerical model allows evaluation of the influence of each of these three forces on the magnitude and direction of the dimensionless water velocity. Water velocity is defined as the sum of the velocity contribution of each force (viscous, capillary and gravity). This model also helps determine favorable scenarios for each force. For instance, the analytic equation and the numerical results show the cases in which one force dominates the others, under given petrophysical and fluid properties and oil or water injection velocity.

Finally, by setting the proper boundary and initial conditions, this model can be used to simulate any displacement in which these three forces interact.
Improved Analytical Model and Experimentally Calibrated Studies of Steam Injection With Hydrocarbon Additives To Enhance Heavy-Oil Recovery
Authors: Simangunsong R. A. , Jaiswal N. J. , Mamora D. D.
Published: December 2007

Experimental, analytical and simulations studies have been conducted to investigate the use of propane and petroleum distillate as steam additives to enhance production to gain a better understanding of production mechanisms of 12°API and 2800 cp heavy oil from San Ardo field, California.

The experiments consist of injecting pure steam, steam- propane, and steam-petroleum distillate into a vertical cell containing a mixture of sand, water and San Ardo oil. The injection cell (68.58 cm long with an ID of 7.376 cm) is placed inside a vacuum jacket, set at the reservoir temperature of 53.3°C. Superheated steam at 230°C is injected at 5.5 ml/min (cold-water equivalent) simultaneously with propane or a petroleum distillate slug. The cell outlet pressure is maintained at 260 psig. Six runs were performed, two runs using pure steam, two steam-propane runs using 5:100 propane:steam mass ratio, and two steam-petroleum distillate runs using 5:100 petroleum distillate:steam mass ratio.

A simplified analytical model is developed to describe steam front advancement and oil production for the 1D displacement experiments. The model incorporates heat and material balance, fillup time and Darcy's law pertaining to the injection cell.

A simulation study was conducted using 1D 48 grid cell model. Satisfactory history matches of the experimental runs were obtained. The analytical and simulation model results are compared against the experimental data to verify the validity of the model.

The main findings of the research are as follows. First, experimental results indicate that compared to pure steam injection, oil production was accelerated by 30% for 5:100.propane:steam injection and 38% for 5:100 petroleum distillate:steam injection respectively. Second, steam injectivity with steam-propane and steam-petroleum distillate increases to 1.4 and 1.9 times respectively, compared with pure steam injection. Third, steam front advancement and oil production data are in good agreement with results based on the analytical and simulation model. The analytical and simulation models indicate that oil production acceleration observed is due to oil viscosity reduction resulting from the addition of propane and petroleum distillate to the steam.
An Evolution from Smart Wells to Smart Fields
Authors: van der Steen E.
Published: December 2007

This paper discusses the "evolution" from Smart Well installations to the delivery of a fully integrated "Smart Field". Capabilities were first developed and tested in nearby fields before being applied in the Champion West field. Results and issues with the component Projects are discussed. The creation of a "Smart Field team" with representation from Petroleum Engineering, Well Engineering, IT, Control and Automation, Data Management/Application, Facility Engineering and Production Engineering is seen as a key enabler for a successful Smart Field development.
Successful Control of High-Pressured Gas Well Using a Crosslinked Gel during Coiled-Tubing Fishing
Authors: Nwoke L. , Arukhe J. , Uchendu C.
Published: December 2007

Good well and reservoir management practices demand that new gas wells be tested to expected potentials at the onset of production and build up surveys carried out at specified intervals during the life of the well. This will help to determine the deliverability of the wells, obtain base reservoir parameters and for reservoir surveillance in monitoring depletion of gas reservoirs. It was in pursuit of the above data gathering that lead to the stalled Multi-rate Build Up survey resulting to stocked temperature and pressure memory gauges at RN-nipple.

The production capability of this well was estimated at 150 MMscf/d of gas. Following the installation of the memory gauges, Multi-rate and 10-hour Build-Up tests were conducted. During the retrieval of the BHP gauges, several incidents lead to three successive fishes getting stocked into the well bore. The Operator was faced with many challenges: ‘do nothing and produce the well in an unsafe manner at 50% potential’, ‘attempt a work over’ or ‘attempt a coiled tubing rigless intervention’, with each option having its attendant limitations.

During the planning stage of the remedial operation, success in retrieving the multiple fishes was identified to come from the ability to kill the high pressure gas well with a time dependent and acid degradable cross-linked gel system through a high rate bullhead pumping technique and appropriate wireline/coiled tubing fishing tools that will simultaneously locate the wire rope and grab it, minimizing run-time in costs effective manner. The kill fluid had low damage potential to the formation was capable of preventing the migration and fingering of formation gas to the surface throughout the fishing operation that lasted for approximately one month of 24-hour day. Key success was also identified to be the ability of coiled tubing to compress wire rope in bunches and exertion of extra over pull to aid in freeing the stuck fish.

At the end of the operation that lasted for one month with difficult challenges; the five (3+2) stuck fishes were successfully retrieved and pre-fishing conduit potential was retained, indicating that the cross-linked gel completely got degraded internally at the end of the fishing operation leaving the near wellbore region undamaged.

The gain from the operation includes leaving the formation in undamaged state after the operation, cost savings, high NPV and escaping from penalty for failing to meet gas contractual obligation if the well is produced at less than programmed production. Over $2.0 million was saved operationally with the choice of rigless activity when compared to other alternatives and the well is still producing satisfactorily after more than five years from the time of this activity.

This paper presents the engineering design, field application and learning from the fishing operations.
Three Dimensional Hybrid DD-FEM Model for Fully Coupled Reservoir Simulation
Authors: Yin S. , Dusseault M. B. , Rothenburg L.
Published: December 2007

In an infinite or semi infinite domain, a petroleum reservoir is seen as a displacement discontinuity; hence, an efficient displacement discontinuity method is used to calculate the stress and displacement changes around a petroleum reservoir. Based on the theory of poroelasticity, a 3-D finite element method is used to account for the local reservoir model. Coupling of the displacement discontinuity method and finite element method, a 3-D large-scale reservoir can be simulated to exist in a poroelastic infinite or semi-infinite domain. The model has been verified and the application is given. Results indicate that the complete overburden response has a significant impact on stress transfer during reservoir depletion.
Review of Issues Associated With Inhibition of Scale-Deposit-Covered Pipelines
Authors: Turgoose S. , Dicken G. E. , Palmer J. W.
Published: December 2007

As reservoirs mature, the amount of water produced increases and velocities reduce. Hence, there is a greater likelihood that deposits will collect at low points in a line. Also, in some instances, poor chemical management may lead to a build-up of scale deposits or corrosion products. All of these factors increase the risk of localised corrosion. In parallel with the above, there is a worldwide requirement to extend the life of ageing assets.

This paper reviews the issues associated with establishing adequate corrosion control in systems that contain significant amounts of deposit, be it sand, scale or corrosion products. Laboratory test data is used to illustrate the effects on corrosion inhibition and the possible consequences with respect to integrity management are highlighted.

Examples include: Inhibition of localised corrosion beneath scalesThe effect of sand beds on inhibitionThe influence of corrosion product films on inhibitor performance.

Novel test procedures are described and the results and conclusions will demonstrate the importance of actively addressing these issues in inhibitor selection programmes.
Factors Controlling the Membrane Efficiency of Shales When Interacting With Water-Based and Oil-Based Muds
Authors: Al-Bazali Talal M. , Zhang Jianguo , Chenevert Martin E. , Sharma Mukul M.
Published: December 2007

This paper presents a comprehensive set of experimental data for the membrane efficiency of four shales when interacting with different water-based and oil-based muds. Pressure transmission tests were used to measure the membrane efficiency using three different cations and two different anions at different concentrations (water activities).

It was found that the measured membrane efficiencies of shales when exposed to salt solutions were low, ranging from 0.18% to 4.23%. Useful correlations are presented between the membrane efficiency and other shale properties. Results suggest that the membrane efficiency of shales is directly proportional to the ratio of the cation exchange capacity and permeability of shales. Higher cation exchange capacities and lower permeabilities correlate very well with higher membrane efficiencies. Moreover, the ratio of the hydrated solute (ion) size to shale pore throat determines a shale's ability to restrict solutes from entering the pore space and controls its membrane efficiency. Cations and anions with large hydrated radii yielded higher membrane efficiencies, compared to ions with small hydrated diameters. Thus, the formulation of drilling fluids must take into account the types of cation and anion in the water-based fluid.

It was also found that the membrane efficiency of oil-based muds was high, however, these membrane efficiencies were not 100 % as postulated by many researchers.
The Drilling and Casing Running Enigma
Authors: Mason C. J. , Chen D. C. -K.
Published: December 2007

Running casing in high angle and extended-reach wells is often recognized as one of the most demanding of all well construction operations. In such wells, frictional drag and unexpected downhole mechanical resistance can exceed available surface slack-off weight. The ability to reliably predict casing running performance will significantly help to reduce costs in challenging wells. Interestingly, a complex and often subtle relationship exists between a drilled wellbore and the subsequent casing run. This relationship is sometimes predictable and at other times surprisingly different. A key to resolving this enigma lies in understanding the many factors, such as wellbore quality, that influence the outcome of casing running operations. The paper reviews a number of topics that are considered key to understanding the relationship between drilling and casing running. Various results are illustrated using case studies from field operations.
Performance of Horizontal Wells in Gas Condensate Reservoirs: Hassi R'Mel Field, Algeria
Authors: Marir Boualem , Tiab Djebbar
Published: December 2007

Hassi R'Mel Field is one of the biggest gas-condensate fields in the world. The southern area of this field, Module 02, has been depleted by vertical wells since 1979.

Since 1981, water production has exceeded the allowed water limit. The salinity of the produced water is about 05 g/l, which is the maximum salinity allowed at the surface facilities. As a result, a sever reservoir damage may have occurred. So the producing reservoir levels (C) were shut-in.

The primary objective of this study is to investigate the performance of horizontal wells in a Sector-Model, to predict their behavior versus water production, and condensate recovery.

To simulate the depletion processes, a compositional simulation is conducted to investigate the following phenomena in the case of horizontal and vertical wells: (a) Water influx effects, (b) Comparison of horizontal well drawdown pressure to that of vertical wells, and (c) The influence of the horizontal well length section and reservoir thickness on horizontal well productivity, and condensate recovery.

A reservoir characterization is made, and a 3-Parameter Peng-Robinson equation of state (3-PR-EOS) is established to characterize the reservoir fluids.

A 3-D Cartesian Sector Model was built for the zone of interest in order to predict the performance of horizontal wells and the different phenomena that can be present in retrograde gas-condensate reservoirs, and to analyze the most relevant reservoir parameters that affect horizontal wells performance.

The obtained results showed that the use of horizontal wells is a proven technology for reducing water influx problems and improving condensate recovery. The condensate production of a horizontal well compared with that of a conventional vertical well can be increased by a factor of 1.30, owing to less condensate accumulation in the region of the producing well.
26-in. Hole Sidetracking Problems in Salman Oil Field, Persian Gulf: A Case Study
Authors: Rahchamani A. , Kalantari-Dahaghi A. M. , Moghadasi J. , Gholami V.
Published: December 2007

This paper describes the reason of sidetracking in 26 inch hole of Salman field in Persian Gulf, its problems and restrictions including unconsolidated formation type, existence of washout below the conductor pipe, probability of anti collision, limitation to survey in order to determine the well situation and short side track interval. Finally the methods for overcoming these problems in order to do a successful sidetrack are explained.
A New Genetic Algorithm (GA) Model Predicts Green-House Gas (GHG) and Reservoir Oil Interaction Parameters More Accurately in Geosequestration Applications
Authors: Emera M. K. , Sarma H. K.
Published: December 2007

The GHG geosequestration in oil and gas reservoirs has recently been receiving much attention, particularly because it also offers an opportunity to concomitantly enhance oil recovery from depleted reservoirs. However, for it to be successful for geosequestration and EOR, it is critical that the GHG-oil miscibility and interactions are favorable and well understood.

This study presents a new genetic algorithm (GA)-based model to predict GHG-oil interaction parameters, notably, GHG-oil solubility, impact on oil swelling factor, GHG-oil density and viscosity. The model utilizes saturation pressure, temperature, oil specific gravity, oil and GHG compositions, GHG critical properties, and equally important, the GHG liquefaction pressure to predict the GHG solubility. The oil-swelling factor is modelled as a function of the oil molecular size and GHG-oil solubility. For the GHG-oil density, the initial oil density, saturation pressure, temperature, and oil specific gravity are used as input variables. The modelling of GHG-oil viscosity takes into account the effects of initial oil viscosity, saturation pressure, temperature, GHG-oil solubility, oil specific gravity, and compositions of oil and GHG.

The model has been successfully validated with published experimental data and has also been compared against other commonly reported models that are developed, essentially, for CO2-oil properties. The GA-based model consistently yields outstanding accuracy (0.48 to 6.2% average error range). Furthermore, the GA-based model can be applied over a much wider range of data under various conditions (wider oil gravities, Ps≤41.37 MPa, T≤141.1°C, and oil MW≤450) and over bigger range of GHG compositions. In addition, this model can easily be incorporated into a reservoir simulator and it can serve as yet another useful experimental protocols design tool.
Commercial Success of Polymer Flooding in Daqing Oilfield—Lessons Learned
Authors: Yupu Wang , He Liu
Published: December 2007

The polymer flooding technology has been applied commercially in Daqing Oilfield since 1996. It has become an important supporting technology for both the stable output of Daqing Oilfield and the development improvement of the mature oilfields. In Daqing Oilfield, the polymer flooding annual output has exceeded 10 million tons; water cut reduction rate has been kept 24.8% for 2 years. In the testing blocks, the average incremental oil recovery over waterflooding is 10.99%. To solve emerging problems in the pilot areas, new techniques and processes have been applied. They are: 1) injection of high concentration slug; 2) polymer injection to separate layers; 3) in depth profile modification. The success of these techniques and processes have enlarged the polymer flooding scale year by year and the technology of polymer flooding itself has been improved. The successful experience of Daqing polymer flooding is valuable for polymer flooding technology development in other countries.
A New Pressure Transient Analysis Model for Water Injection Well in Dual-Porosity Reservoirs
Authors: Shimamoto T. , Kuramoto D. , Arihara N. , Onishi T.
Published: December 2007

This paper presents a new analytical model for pressure transient tests of water injection wells in naturally fractured reservoirs. Considering negligible flow in matrix, the dual-porosity model was assumed for formulating a mathematical model that accounts for two-phase flow and saturation changes in fracture and matrix. Water saturation distributions in fracture and matrix were calculated analytically using the Buckley-Leverett equation and the empirical transfer function to account for fracture-matrix flow. Pressure equations for two-phase flow were formulated with the multi-composite modeling approach. The system of pressure equations was solved analytically in Laplace space. Calculations were carried out stepwise as the injection or falloff time proceeds.

The model solutions were validated for such special cases as single-phase flow in the dual-porosity model, and two-phase flow in the single-porosity model. Pressure and pressure-derivative type-curves, graphed against the injection time or the dimensionless time based on well radius, exhibited features of both fractured reservoirs and two-phase flow. The parameters in the type curves are storativity ratio, interporosity two-phase flow coefficient defined as a function of shape factor, total mobilities for matrix and fracture, and exponential recovery constant Rc. Rc characterizes imbibitiondominant recovery performance of matrix, and is defined as a function of permeability, porosity and capillary pressure of matrix, and shape factor.
Characterizing Sparsely Fractured Reservoirs Through Structural Parameters, Time-Lapse 3D Seismic, and Production Data
Authors: Zeidouni M. , van Kruijsdijk C. P. J. W.
Published: December 2007

In the case of fractured reservoirs the productivity is primarily based on the fracture density, thus structural parameterisation becomes highly important. In conventional history matching, the process of conditioning the reservoir model to the historical dynamic data, the production data are utilised to condition the model. Based on the nature of production data the model can be parameterised by reservoir parameters only and the structural and geological inputs are kept fixed. Given time-lapse 3-D seismic the procedure might be altered and structural parameterisation becomes possible.

In this paper we evaluate the benefit of using time-lapse seismic to model the fractured reservoir with structural parameters, i.e. to locate the fractures. A synthetic sparsely fractured reservoir is modelled and parameterised structurally based upon the length and position (x and y coordinates) of the fractures. A compressional-wave velocity model is developed to enable the comparison of seismic data and reservoir data (saturation and pressure). A production, pressure, and saturation profile is simulated and results are compared with history through an automated history matching loop.

The advantageous of the seismic and production data in parameters' evaluation is examined. The well data are found very efficient in defining the parameters that are involved in production. Time-lapse seismic data grants information about all the parameters, but over a wide confidence interval. The results depend strongly on the times of acquiring seismic surveys as well as the number of unknown parameters. As the number of parameters is increasing, the efficiency of seismic comparing to that of well data increases. The optimal times for acquiring seismic data can be found through modelled saturation profiles. Extracted pressure data from time-lapse seismic proved to be very valuable in fractured reservoir modelling because of the pressure anomaly between the matrix and the fracture. The uncertainty of the resulted parameters due to the measurement error of the data is also analysed.
Formation of Underwater Cuttings Piles in Offshore Drilling
Authors: Fang Qian , Guo Boyun , Ghalambor Ali
Published: December 2007

Discharge of drill cuttings to seabed can significantly reduce offshore drilling cost. However, formation of cuttings piles on seabed near the rig site can present problems for drilling and production operations. When the problem is likely to occur in the areas of low current velocity, the cuttings are not discharged to seabed but ground and injected to formation, or transported to onshore for disposal, which increases drilling cost. It is highly desired to have an accurate method to predict the location and configuration of the cuttings piles in the design stage of well drilling. This paper presents a solution to the problem.

Starting from Newton's second law of motion, a mathematical model has been developed in this study to predict the location, configuration, and characteristics of cuttings piles. Factors considered include water depth, current velocity, cuttings properties (size distribution, density, and sphericity), and water properties (density and viscosity). This mathematical model has been computerized. It provides well planners a useful tool for predicting the characteristics of cuttings piles during drilling. Application of the tool can reduce cost of drilling through better handling of drill cuttings such as discharging to water versus injecting into formation.
Case Studies—Proactive Managed Pressure Drilling and Underbalanced Drilling Application in San Joaquin Wells, Venezuela
Authors: Beltran J. C. , Gabaldon O. , Puerto G. , Alvarado P. , Varon V.
Published: December 2007

The San Joaquin field was discovered in the 1930's and is one of the largest oil-gas fields in the eastern Venezuela. It field currently including over 240 wells producing from 662 different reservoirs. The average daily production is about 800 MMSCFGD and 8000 BOD of condensate.

Due to the reservoir characteristics and the natural decrease of the reservoirs virgin pressure, drilling operations applying conventional overbalanced methods have induced significant Operational Problems and formation damage.

To reduce initially the operational problems (average fluid losses, which were more than 2,000 barrels per well) and to decrease Productivity Index damages due to differential pressures on the depleted formations, the Near/Under Balanced technique was considered.

Several months of reservoir evaluations with geomechanical and stability studies were spent, before the decision to use Managed Pressure Drilling through-out shale/sandstone-layered gas payzones formations was taken.

Twelve wells have been performed up to date using proactive Managed Pressure Drilling (MPD) & Underbalanced Drilling (UBD) techniques in the Merecure and San Juan formations (8½″ and 6½″ hole sections respectively). Nitrogen injection has been applied in the San Juan formation to achieve the required ECD below 6.0 ppg.

These types of wells were the first of their kind drilled in Latin America using these techniques in conjunction with the Down Hole Deployment Valve (DDV).

The application of the MPD technology to solve the varied range of operational problems that had been experienced in the San Joaquin field, began in December 2004 in the 8½″ section of the G-92 well, with an excellent operational and production result. After this milestone, the MPD program has included the performance of the following wells, up today: JM-229, JM-230, JM-233, JM-235, JM-236, JM-237, JM-238, JM-239, G-96, JM-240, JM-242.

A total of sixty days and US$1.4 Million have been saved using the above practice in the first five wells (8½″ and 6½″ hole sections). As a result, PDVSA will continue applying the technique in the San Joaquin field. The well bore stability study is currently under evaluation for the 12 ¼″ hole section to enable the MPD application in an effort to optimize time and costs in the upper section too.

This paper describes how the planning and operational procedures have been performed in order to obtain savings during the drilling activity in San Joaquin wells and How the improvements in the production are being achieved following a great step forward in today's industry needs for recovering production from complex reservoirs.