bluuebunny/crossref_metadata_2025 huggingface dataset:
Operating Limit of Gas Well Gravel Packed Completions – A Flux-Based Approach
Authors: Nnanna Erasmus , Ayoola Olakunle
Published: June 2014

A technique for determining the operating limit of internal gravel packed (IGP) gas wells has been developed. Consistent with the observations by Tiffin et al1 and Keck et al2, the non-dependence of sandface completion failure on pressure drawdown is established for 20 IGP gas wells in SPDC portfolio. Downhole flow velocity (flux) had earlier been established as the main factor contributing to screen erosion and GP failure (King et a1l and Tiffin et al2). Therefore, a flux-based operating limit for IGP gas wells is developed using Reynolds Number (NRe) evaluated at downhole conditions. Input data include production rate, perforation details and fluid properties.

Well files were reviewed to identify gas wells with screen erosion IGP failures. For such wells, the pressure drawdown, rate and fluid properties at the period of failure were captured for calculation of the flux and NRe. For comparison, a similar analysis was carried out for wells with healthy gravel packs. The maximum NRe for healthy gravel packs was established as 90,000 while the minimum for failed gravel packs was 200,000 suggesting the existence of a limiting NRe beyond which IGP failure occurs.

The applicability of the technique was demonstrated for a gas field requiring swing production commonly used to make up for supply shortfalls. The technique was also used to determine a theoretical maximum flux and maximum production rates for all the SPDC IGP gas wells.
Evaluation of Scale Inhibitors Suitable For Deepwater Fields
Authors: Guan Hua , Farmer Paul
Published: June 2014

The increasing demands for oil and gas require production from increasingly deeper water depths resulting in demands for production chemicals that are suitable for deepwater and ultra-deepwater fields. The specific challenges for production chemicals in deepwater fields include bigger temperature fluctuations from seabed temperature to high-temperature/high-pressure (HTHP) environments, higher shear rates, greater pumping pressures, longer residence time and limited injection lines.

To address these issues, this paper demonstrates the whole suite of laboratory evaluation techniques that simulates the conditions experienced in the deepwater fields. These techniques include the exposure of production chemicals to a high-pressure flow loop with cyclic temperature variation from seabed temperature to 212°F (100°C), the measurement of rheology profiles at ambient and high pressure (5,000 psi), thermal stability and material compatibility. Several scale inhibitor products, including combined scale/corrosion inhibitors, have gone through the full suite of deepwater condition testing to determine their suitability for deepwater fields. Performance testing was also conducted for both pre- and post-flow loop samples. The best candidates have been designed to maintain similar inhibition performance after the flow loop with a viscosity less than 33 cP at 39.2°F (4°C) under 5,000-psi conditions; these products also have to be thermally stable and compatible with methanol/glycols and various elastomers used.

This paper provides insights into the suitable laboratory techniques and criteria for the evaluation of deepwater products. The wide range of temperature variations, high shear, long residence time and HTHP environment for the deepwater fields has been successfully simulated in the laboratory and used to evaluate deepwater scale inhibitors.
Improved Heavy-Oil Recovery by Separated-Zones Horizontal-Well Steam Stimulation
Authors: Zhong Liguo , Zhang Shoujun , Wu Fei , Lang Baoshan , Liu Heng
Published: June 2014

Horizontal wells are widely drilled to produce heavy oil because of their large reservoir contact. For example, there are more than 500 horizontal wells operated in cyclic-steam-stimulation (CSS) or steam-assisted gravity-drainage (SAGD) processes in Liaohe oil field. The length of these horizontal wells usually ranges from 100 to 500 m. But it is challenging to recover oil along a horizontal well proportionally by conventional steam-injection processes because of poor steam conformance along the horizontal well, which is derived from reservoir heterogeneity, large horizontal-well length, and steam properties. Field investigation shows that only half of the reservoir along the horizontal well is well steamed and recovered, and that the average ratio of oil production to steam injection (OSR) is less than 0.28. In this paper, a separated-zones steam-injection process is introduced to improve steam conformance along the horizontal well; in this process, in which packers, outlets, pressure-sensitive valves, and ball sealers are involved, steam could be injected to the selected zone, separated dual zones in sequence or at one time, or separated multizones simultaneously. In order to investigate steam conformance along the horizontal well and feasibility of separated-zones steam injection, primary laboratory experiments with a sand-packaged model, numerical simulation, and field testing are carried out. These show that steam injected to separated zones could be regulated with sealed packer(s) based on the principles of steam crossflow and superimposing the effect near the packer; therefore, steam conformance along the horizontal well could be considerably improved by separated-zones steam injection. Field testing of 76 wells stimulated by separated-zones steam injection shows that up to 70% of the reservoir along the horizontal well is well steamed on average, and steam conformance is significantly improved.
CO2 Injection in Vertical and Horizontal Cores: Measurements and Numerical Simulation
Authors: Moortgat Joachim , Firoozabadi Abbas , Li Zhidong , Espósito Rogério
Published: June 2014

In certain high-pressure and low-temperature reservoirs, the density of CO2 may be substantially higher than the oil density. Upon mixing of CO2 and oil, a gas phase with a high content of methane (C1) may also appear. When the C1 content is high, this gas phase may have a lower density than the oil. In relation to this phenomenon, we have conducted three comprehensive experiments studying CO2 injection from the top and bottom of a vertical core and injection in a horizontal core. The injection rate is 1 PV/day. This low rate allows the study of diffusion. The core diameter used in this work is 3.8 cm and the length is 27.3 cm. The tests are conducted at a pressure of 441 bar and a temperature of 60°C. At 2.6 hydrocarbon pore volume injection (PVI), the coreflood results give a recovery of 98% for bottom injection, 84% for top injection, and 92% for horizontal injection. We have also conducted an extensive set of measurements to determine swelling, viscosity, and density for the calibration of an equation of state. We simulate the experiments using a state-of-the-art higher-order finite-element three-phase compositional model. The simulations suggest that the endpoint relative permeability of the CO2-rich phase may be lower than the oil phase. The results also show that Fickian diffusion should be taken into account, but that the diffusion coefficients are reduced, because the CO2/oil mixtures are in the near-critical region for much of the injection. Even for a horizontal core there is a considerable gravity effect. One main conclusion is that there may be vast differences between CO2 injection in a 1D slim tube and in a core where there may be a 2D flow. A related conclusion is that analysis of CO2 coreflooding may provide important parameters for field-scale problems.
When Unconventional Becomes Conventional
Authors: Stefik Ron G. , Paulson Ken
Published: June 2014

British Columbia (B.C.) has seen near-exponential growth in the areas of the Horn River and Montney unconventional shale-gas plays situated in northeastern B.C. (Fig. 1). The original-gas-in-place volume for the Montney and Horn River basins has not been formally calculated, but it has been estimated at greater than 500 Tcf and continues to be revised upwardly as new and more-refined information is obtained and development takes place. The Cordova embayment and Liard basin, east and west (respectively) of the Horn River basin, are at early stages of assessment but promise additional massive gas-in-place values.

Approximately 5 years ago, industry experts were predicting a dramatic reduction in viable gas production from the western Canada sedimentary basin, and from North America in general. Market predictions were favouring investment in import terminals for liquefied natural gas (LNG), in which gas from offshore suppliers could be imported and moved through the North American transportation grid to market. Regulators were anticipating an influx of LNG-facility applications and myriad infrastructure modifications to handle the resulting new flow regime.

In 5 short years, this dire future has been reversed completely because of the advent of economically viable methods to access gas trapped in shales and similar tight formations. At the current rates of production and exploration, there are more than 20 years of gas reserves in B.C., reversing a previous decline, as shown in Fig. 2.

B.C. is ideally positioned to provide gas to North America with ready access to a number of major gas-transportation pipelines, including systems operated by TransCanada Pipelines, Spectra Energy Gas Transmission, and the Alliance Pipeline. Many of these systems are undergoing significant capacity expansions to accommodate the influx of gas from these new plays.

This paper will explore the challenges posed to regulators in rapidly moving from conventional vertical-well developments to unconventional multiwell pads consisting of multiple fracture-stimulated horizontal wells.
Natural Gas: The Green Fuel of the Future
Authors: Taylor Robert , Tertzakian Peter , Wall Tim , Graham Mike , Young Peter J , Harbinson Sheldon
Published: June 2014

As populations and economies continue to grow globally, energy demand will grow proportionally. Extensive work by Tertzakian (2007, 2009) has shown crude-oil supplies may not keep pace with this increased demand. The shortfall must be met by other energy sources.

Only two current energy sources have the global capacity to, by themselves, address increased energy demand in a timely manner. These are natural gas and coal.

Traditionally, the major use of crude oil has been for processing into transportation fuels, with lesser amounts being used for petrochemicals and home heating. Natural gas and coal have been used primarily for electrical generation and heating.

A pivotal transition will likely occur in which natural gas and coal begin to see increased use as transportation fuels. A battle for market share between primary fuels will likely ensue.

The objective of this paper is to present data comparing the environmental impact of using methane vs. coal. A compelling case for the use of natural gas as the future "green fuel" emerges.
Waste Management for Drillers
Authors: Gogan Ray , Vencenzo Mattia , Ayapbergenov Yerzhan
Published: June 2014

Karachaganak Petroleum Operating B.V. (KPO) has implemented waste management process that maximizes waste reduction and waste reuse. Minimizing environmental impact was also a primary focus. This process incorporates waste minimization / segregation, oily water treatment, oil-based mud (OBM) drilled cuttings treatment and recycling of drilling muds and brines. KPO is now completing the central treatment site where it has deployed new equipment and which places it at the top of the international ladder as far as recycling, treatment and safe disposal of drilling fluids and drilling wastes are concerned. In arriving at this milestone KPO completed a 'Best Available Techniques' (BAT) review of drilling waste which is based on a review of worldwide handling and disposal techniques. This paper describes the current waste management practices established by KPO and the strategies identified by KPO for the final end point for the drilling wastes at the Karachaganak field in north-western part of the Republic of Kazakhstan.
Cuttings Re-Injection as an Environmentally Safe and Economically Efficient Drilling Waste Management Option for Karachaganak Field
Authors: Gogan R.. , Mattia V.. , Oates M.. , Gumarov S.. , Shokanov T.. , Mangiameli R.. , Simmons S.. , Boyles G.. , Woolsley G..
Published: June 2014

While engineered, operated and monitored properly, Cuttings Re-Injection or Waste Injection (WI) - injection of drilling generated waste into selected subsurface formations through initiation of disposal fractures - has proven to be an environmentally friendly and cost-effective waste management technology allowing compliance with "zero discharge" requirements. Areas where it is becoming the technology of choice are continuously expanding and the FSU (Former Soviet Union) is not an exception. The first WI project in this region started in Russia (offshore Sakhalin) in 2000 and then was followed by projects in Azerbaijan (ACG) in 2006 and mainland Russia (Western Siberia) in 20081,2,3. To date, more than 4.5 MM barrels of waste have been safely injected in the region with extremely low NPT – 0.01%.

Karachaganak is a giant gas-condensate field in Kazakhstan operated by KPO. Re-injection of drilling generated waste into a selected subsurface formation has been under investigation as a potential waste management option for the field for a few years. Lithostratigraphy and geological characteristics of sub-surface formations were investigated to identify availability of suitable intervals for cuttings injection. Further, a feasibility study identified thick interbedded sandstone/claystones of the Triassic and Upper Permian, as suitable for WI purposes. Hydraulic fracture simulations showed containment of disposal fractures within the target injection intervals and indicated sufficient disposal capacity of selected formations. Once the potential disposal formations were identified, the basic surface equipment and facilities capable of safely handling expected drilling waste was designed. Additionally, as there was no actual precedence of WI technology implementation in Kazakhstan, local regulations were briefly reviewed.

Summarizing, the given paper outlines results of feasibility investigation and required surface facility and equipment parameters for WI technology implementation in the Karachaganak field.
Water Disposal Case Study in Karachaganak Field
Authors: Karibay B..
Published: June 2014

One of the essential problems in the development of oil and gas fields is the proper management of the industrial wastewater handling in order to prevent environmental pollution and provide a reliable utilization of potentially environmentally hazardous waste. As a result of technological operations at the Karachaganak field, industrial water is generated at the facilities, which is utilized by injecting it between the isolated salt dome depositions. The purpose of this paper is to provide information about the industrial water handling process in the Karachaganak field, and to facilitate knowledge sharing, and promotion of experience exchange.

The following topics are considered: review of the industrial wastewater disposal system in operation at the Karachaganak field; the wastewater disposal challenges associated with hydrocarbon production and the effect of additional development of the field on the disposal requirements; ways of optimization of the disposal system; acid stimulation as a solution to the well injectivity decline; effluent analysis; monitoring and proper measurement of injection volumes and limitations of the disposal system including capacity of the disposal polygons; injection volume allocation and the inaccuracy in the measurement of the disposal volumes during simultaneous injection; the maximum allowable water injection pressure.

From the beginning of the Karachaganak field development, KPO b.v. has accumulated a vast amount of knowledge in wastewater handling that can provide a useful basis from which to optimize and enhance future wastewater related processes. It is important to understand, however, that the development of the wastewater handling is dependant on the total field development, where the risks associated with the production forecasting affect all aspects of the oil and gas field development chain.
Robust and Efficient Handling of Model Constraints with the Kernel-Based Ensemble Kalman Filter
Authors: Sarma Pallav , Chen Wen H.
Published: June 2014

The ensemble Kalman filter (EnKF) has recently received significant attention as a robust and efficient tool for data assimilation. Although the EnKF has many advantages such as ease of implementation and efficient uncertainty quantification, it is technically appropriate only for random fields (e.g., permeability) characterized by two-point geostatistics (multi-Gaussian random fields). Realistic systems however are much better described by multi-point geostatistics (non-Gaussian random fields), which is capable of representing key geological structures such as channels. Furthermore, the updating step in the EnKF can lead to non-physical updates of model states and other variables (such as saturations), and this problem is evident in highly nonlinear problems like compositional simulation.

In a recent paper (Sarma and Chen, 2009), we formulated a generalized EnKF using kernels (KEnKF), capable of representing non-Gaussian random fields characterized by multi-point geostatistics. In this work, we further extend the KEnKF to efficiently handle constraints on the state and other variables of the simulation model, arising from physical or other reasons. In the standard EnKF, the usual approach to handle constraints is through truncation or variable transformation, which has been shown to be problematic for highly nonlinear problems. In the KEnKF, because the Kalman update equation is solved as a minimization problem, constraints can be easily and rigorously handled via solution of a constrained nonlinear programming problem. We propose a combination of fixed point iteration and the augmented Lagrangian method to solve this problem efficiently. Note that with a kernel of order 1, the KEnKF is equivalent to the standard EnKF, and therefore, the proposed approach to handle constraints is applicable even if high order kernels are not used. The procedure is demonstrated on an example case, and is shown to better handle various state constraints compared to the standard EnKF with truncation.
Acid Diversion by Use of Viscoelastic Surfactants: The Effects of Flow Rate and Initial Permeability Contrast
Authors: Al-Ghamdi A.H.. H. , Mahmoud M.A.. A. , Wang G.. , Hill A.D.. D. , Nasr-El-Din H.A.. A.
Published: June 2014

The purpose of matrix stimulation in carbonate reservoirs is to bypass damaged areas and increase the effective wellbore area. This can be achieved by creating highly conductive flow channels known as wormholes. A further injection of the acid will follow a wormhole path where the permeability has increased significantly, leaving substantial intervals untreated. This problem can be more significant as the contrast in permeability increases within the target zones. Diverting materials, such as viscoelastic-surfactant (VES) -based acids, play an important role in mitigating this problem.

The acid-injection rate was found to be a critical parameter to maximize the efficiency of the use of VES-based acids as a diverting chemical in addition to creating wormholes. It was found that the maximum apparent viscosity, which developed during VES-based-acids injection, occurred over a narrow window of acid-injection rates. Higher injection rates were not effective in enhancing the acidizing process, and the use of diverting material became similar in effect to that of regular acids. The use of VES-based acid was also found to be constrained by the scale of the initial permeability ratio. For initial permeability ratios greater than approximately 10, the diversion was insufficient.

The results were obtained by conducting a large set of acidizing experiments by use of 20-in.-long cores. Both single- and parallel-coreflood experiments were performed in this study. Carbonate cores were used with initial permeabilities of 4–150 md, and the flow rate was varied from 1.5 to 50 cm3/min. The initial ratio of permeability between the two cores ranged from 2 to 15. To characterize the wormholes, computerized tomography (CT) was used to generate a 3D view of the wormholes in each core.

By use of the results obtained from single cores, the acid-injection rate was found to be a critical parameter in maximizing the efficiency of the use of VES as a diverting agent during matrix-acidizing treatments. Higher injection rates were not effective in enhancing the acidizing process, and the use of diverting material produced results similar to those of regular hydrochloric acid (HCl). Parallel-coreflood experiments indicated that the use was found to be constrained by the scale of the initial permeability ratio. For initial permeability ratios greater than approximately 10, diversion was insufficient in 20-in. coreflood tests. For permeability ratios greater than 10, the acid-placement treatment needs to be designed more carefully.
Pore-Pressure and Wellbore-Stability Prediction To Increase Drilling Efficiency
Authors: Li Shuling , George Jeff , Purdy Cary
Published: June 2014

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Abstract

Pore pressure and wellbore stability pose significant challenges to exploration drilling, particularly in regions featuring weaker rocks or subsalt formations. A lack of accurate pore-pressure prediction and wellbore-stability analysis brings many problems, such as blowouts, kicks, hole washouts, wellbore breakout, and stuck pipe. Wellbore instability also adds to drilling time and increased costs, and sometimes leads to abandoning the well before it reaches its objective. Estimates put the cost of these issues at approximately 10% of total drilling time on average. Ending wellbore-instability problems begins with the ability to predict conditions accurately and to reduce the chance of running into trouble. In this paper, commonly used methods for analyses of pore pressure, in-situ stress, and borehole shear failure are evaluated for their strengths and weaknesses. Examples are provided that demonstrate that the integration of predrill pore-pressure and geomechanics analyses with real-time monitoring consistently provides an effective way to mitigate predrill uncertainties and improve well-construction efficiency.
Constant-Pressure Gas Porosimeter
Authors: Heim A.H.
Published: June 2014

A method and apparatus for measuring gas porosities of rocks are described. The apparatus can be assembled from commercially available components. In principle, measurements are made by volume substitution at constant pressure. The maximum error is not more than 0.3 porosity per cent. Typical results are given.

Introduction

Determining the porosity of rock samples is one of the most important and yet most varied types of measurement in core analysis. Among the many techniques devised are the so-called "gas porosity" methods. An old and well known example is the Washburn-Bunting method. The U.S. Bureau of Mines described and later improved the apparatus for a now widely used method generally known as the "Boyle's law" method.

In the present form of the Washburn-Bunting method, the volume of air in the pores of a rock sample at atmospheric pressure is extracted and then collected in a graduated burette at atmospheric pressure. The volume of air is read directly as the pore volume of the sample. The absolute error in reading the collected volume of gas is independent of the total volume; thus, the relative error is larger when the volume is small, as it is for rocks of low porosity. In addition, the sample after measurement contains mercury, which limits its use for other analyses.

The Bureau of Mines (or Boyle's law) method measures directly the solids volume of a sample from which the pore volume and porosity are derived, using a separate measurement of the bulk volume. Gas at a few atmospheres pressure is introduced into a sample chamber of known volume containing the rock sample. The pressure is accurately measured. Following, the gas is expanded into a burette at 1 atm, and the gas volume is read directly. From the initial pressure p1 and the final pressure p2 and volume v2, the initial gas volume v1 is calculated using Boyle's law; that is, p1v1 = p2v2. Volume v1 minus the volume of the empty sample chamber is the solids volume of the sample. The accuracy of the method is limited, unless corrections are made, by deviations of the gas from the "ideal" gas-law behavior assumed in the simple form of Boyle's law.
The Use of Rate-Transient-Analysis Modeling To Quantify Uncertainties in Commingled Tight Gas Production-Forecasting and Decline-Analysis Parameters in the Alberta Deep Basin
Authors: Luo H. , Mahiya G. F. , Pannett S. , Benham P.
Published: June 2014

The evaluation of expected ultimate recovery (EUR) for tight gas wells has generally relied upon the Arps equation for decline-curve analysis (DCA) as a popular approach. However, it is typical in tight gas reservoirs to have limited production history that has yet to reach boundary-dominated flow because of the low permeability of such systems. Commingled production makes the situation even more complicated with multiboundary behavior. When suitable analogs are not available, rate-transient analysis (RTA) can play an important role to justify DCA assumptions for production forecasting.

The Deep-basin East field has been developed with hydraulically fractured vertical wells through commingled production from multiple formations since 2002. To evaluate potential of this field, DCA type curves for various areas were established according to well performance and geological trending. Multiple-segment DCA methodology demonstrated reasonable forecasts, in which one Arps equation is used to describe the rapidly decreasing transient period in early time and another equation is used for boundary-dominated flow. However, a limitation of this approach is the uncertainty of the forecast in the absence of extended production data because the EUR can be sensitive to adjustments in some assumed DCA parameters of the second segment. In this paper, we used RTA to assess reservoir and fracture properties in multiple layers and built RTA-type well models around which uncertainty analyses were performed. The distributions of the model properties were then used in Monte Carlo analysis to forecast production and define uncertainty ranges for EUR and DCA parameters. The resulting forecasts and EUR distribution from RTA modeling generally support the DCA assumptions used for the type curves for corresponding areas of the field. The study also showed how the contribution from the various commingled layers changes with time. The proposed workflow provides a fit-for-purpose way to quantify uncertainties in tight gas production forecasting, especially for cases when production history is limited and field-level numerical simulation is not practicable.
Bayesian Probabilistic Decline-Curve Analysis Reliably Quantifies Uncertainty in Shale-Well-Production Forecasts
Authors: Gong Xinglai , Gonzalez Raul , McVay Duane A. , Hart Jeffrey D.
Published: June 2014

Several analytical decline-curve models have been developed recently for shale-gas wells (Ilk et al. 2008; Anderson et al. 2010; Valko and Lee 2010). However, these authors did not quantify the uncertainty in production forecasts and reserves estimates. This is important because most shale plays are in the early stages of production and virtually any method will have large uncertainty when there are limited production data available. Jochen and Spivey (1996) and Cheng et al. (2010) developed bootstrap methods that can generate probabilistic decline forecasts and quantify reserves uncertainty. Hindcasts with the modified bootstrap method (MBM) (Cheng et al. 2010) provide good coverage of the true cumulative production. However, the authors did not show they can quantify reserves uncertainty with limited production data in unconventional plays.

In this paper, we introduce a Bayesian probabilistic methodology using Markov-chain Monte Carlo (MCMC) combined with Arps' decline-curve analysis. We tested this model on two data sets: Barnett shale horizontal-well gas production with more than 7 years of history and Eagle Ford shale horizontal-well oil production with more than 1 year of history. In both cases, P50 hindcasts were very close to true cumulative production and P90 and P10 hindcasts quantified the cumulative production uncertainty reliably with as little as 6 months of production available for matching.

In this Bayesian methodology, the decline-curve parameters qi, Di, and b are assumed to be random variables instead of parameters to be modified to obtain a best fit. A Markov chain of the decline-curve parameters is constructed by use of MCMC with the Metropolis algorithm (random walk). We developed the model by performing hindcasts with the Barnett case study consisting of 197 horizontal gas wells with more than 7 years of production. The prior distribution, proposal distribution, and likelihood function were calibrated so the probabilistic decline curves quantified the cumulative-production uncertainty reliably with as little as 6 months of data. The same model was then tested with analysis of Eagle Ford shale oil production from 536 wells; the probabilistic decline curves quantified the cumulative-production uncertainty reasonably well by changing only the prior distribution.

The proposed Bayesian methodology provides a means and a workflow to generate probabilistic decline-curve forecasts and quantify reserves uncertainty in shale plays quickly and reliably. This Bayesian methodology can also be applied with other analytical decline-curve models if desired.
Well/Wormhole Model of Cold Heavy-Oil Production With Sand
Authors: Istchenko C.M.. M. , Gates I.D.. D.
Published: June 2014

Cold heavy-oil production with sand (CHOPS) is a nonthermal heavy-oil-recovery technique used primarily in the heavy-oil belt in eastern Alberta, Canada, and western Saskatchewan, Canada. Under CHOPS, typical recovery factors are between 5 and 15%, with the average being less than 10%. This leaves approximately 90% of the oil in the ground after the process becomes uneconomic, making CHOPS wells and fields prime candidates for enhanced-oil-recovery (EOR) follow-up process field optimization. CHOPS wells show an enhancement in production rates compared with conventional primary production, which is explained by the formation of high-permeability channels known as wormholes. The formation of wormholes has been shown to exist in laboratory experiments as well as field experiments conducted with fluorescein dyes. The major mechanisms for CHOPS production are foamy oil flow, sand failure (or fluidization), and sand production. Foamy oil flow aids in mobilizing sand and reservoir fluids, leading to the formation of wormholes. Foamy oil behavior cannot be effectively modeled by conventional pressure/volume/temperature (PVT) behavior. Here, a new well/wormhole model for CHOPS is proposed. The well/wormhole model uses a kinetic model to deal with foamy oil behavior, and sand is mobilized because of sand failure determined by a minimum fluidization velocity. The individual wormholes are modeled in a simulator as an extension of a production well. The model grows the well/wormhole dynamically within the reservoir according to a growth criterion set by the fluidization velocity of sand along the existing well/wormhole. If the growth criterion is satisfied, the wormhole extends in the appropriate direction; otherwise, production continues from the existing well/wormhole until the criterion is met. The proposed model incorporates sand production and reproduces the general production behavior of a typical CHOPS well.
Analysis of Gravity Drainage
Authors: Hall H.N.
Published: June 2014

Various factors must be considered in an engineering evaluation of gravity-drainage reservoirs. Among these are:the effect of producing rate on total oil recovery;the effect upon well productivity and ultimate recovery of the pressure level maintained during the producing life of the reservoir;the economic advantage of full or partial pressure maintenance; andestimate of the rate of gas production and injection and the possible purchase of gas under conditions of full pressure maintenance to ascertain compressor facilities needed.

All of these factors can be evaluated only when a reliable method is employed for determining reservoir performance in gravity-drainage reservoirs.

The purpose of this paper is to present a general method for calculating the performance of a gravity - drainage reservoir. This method is applicable for conditions of complete pressure maintenance, partial pressure maintenance and normal pressure depletion. Provisions are made to take into account variations throughout the reservoir of reservoir configuration, changes in permeability and fluid composition.

Based on the method presented in this paper, an IBM 650 computer program has been developed. The past performance of an actual gravity-drainage reservoir producing under conditions of declining pressure and no gas injection was duplicated using this program.

Introduction

In tilted reservoirs the production of oil is influenced by drainage of oil from upstructure to downstructure locations. When this downstructure drainage of oil is sufficient to cause effective segregation of the gas and oil in a reservoir, the reservoir is usually classified as a segregation drive or gravity-drainage reservoir. (Discussion will be restricted to gravity-drainage reservoirs which have no encroachment of edge water.) The important feature in gravity-drainage reservoirs is the density difference between reservoir oil and gas. These phases tend to segregate in the reservoir with the result that in the gas cap the oil saturation is maintained at a higher level by drainage of oil from the gas-cap area. Oil can be produced from the oil zone at a low gas-oil ratio and reservoir energy is thereby conserved.
Stranded Gas in the Netherlands: What is the Potential?
Authors: Schulte Ruud , Lutgert Jan , Asschert Annemiek
Published: June 2014

In recent years, gas production in the Netherlands has peaked and appears to have gone into a slow but continuous decline. In an attempt to arrest this decline the Dutch government is investigating possibilities to tap into a previously unattractive class of reservoirs: the stranded fields.

Since the fifties, some 440 gas fields and 45 oilfields have been discovered in the on- and off-shore sectors of the Netherlands. Total gas reserves amount to over 4500 BCM of which some 71% has been produced. Oil reserves amount to 1.15 billion barrels of which 75% has been produced. From the 485 proven fields around 120 accumulations have not been developed and are considered stranded fields. Total volumes in these "contingent resources" amount to over 200 BCM GIIP and over 60 million m3 STOIIP. Tight reservoirs, distant infrastructure, small volumes, and anomalous gas qualities are amongst the main reasons why these resources have not yet been developed.

In this paper, a screening methodology will be presented showing which of these fields might still qualify for development given recent technological and economic changes. By applying a hybrid methodology of GIS tools, data-mining applications and a quick screening economic evaluation the most attractive candidates for development are highlighted. In addition, the impact of new/improved technology, CAPEX changes or tax changes on the development economics are being modeled.

In order to renew interest in these stranded fields it is the intention of the Dutch Government to share results both on the data used for the analysis and any notional development options resulting from this exercise.
Economic Optimization of a Development Program for a Low-Permeability Reservoir
Authors: Hodgson R.N. , Clark G.C. , Rowe M.D.
Published: June 2014

Introduction

To evaluate the development of the Sacatosa field, Maverick County, Tex., which is a marginal reserve field, a complete computer study was made. The computer phase of the work was performed to determine, first, if the field could be economically developed and, if so, to determine the best completion methods and well-spacing patterns to use.

To answer these questions, a numerical solution of the two-phase flow equations developed originally by Muskat, the Howard-Fast equation for fracture extension, and an economic computer simulation model for analysis of the various economic factors involved in a field wide development program were utilized.

Prior to any of the computer work, it was necessary to conduct an extensive field-testing program to gather sufficient data for the various computer phases. This testing involved primarily the determination of initial reservoir pressure, producing bottom-hole pressure and obtaining representative fluid samples. Considerable emphasis was also placed on obtaining accurate producing GOR's; and, as a result, special metering separators were installed on three test wells. Field data also were obtained which indicated the fracture techniques used yield horizontal, single-plane fractures.

Additional data (Table 1) also were available on the reservoir properties, plus the early producing rates from a series of test wells drilled to aid evaluation of the field.

Historical Background

Three wells were drilled in 1957 to initially evaluate the field. One of these wells was unfractured and never attained production greater than 8 B/D, and this only after stimulation with 150 quarts of nitroglycerin. The other two wells were fractured - one with a 66,690-gal, single-plane treatment and the second with a dual-plane treatment, one of 17,640 gal and the other of 51,000 gal of lease crude with 1 lb of 20–40 mesh sand/gal. At the time of the computer study, these wells were the only ones available to provide any indication of production trends for an extended period. As a result, these wells were tested to provide producing bottom-hole pressures so that a check point would be available in solving the flow equations, that is, producing bottom-hole pressure after about 10,000 bbl of stock-tank oil production at an average rate of 18 B/D.
Productivity Increase Using Hydraulic Fracturing in Conventional and Tight Gas Reservoirs – Expectation vs. Reality
Authors: Rahim Zillur , Al-Anazi Hamoud , Al-Kanaan Adnan , Habbtar Ali , Al-Omair Ahmed , Senturk Nejla , Kalinin Daniel
Published: June 2014

Hydraulic fracturing technology is widely used to facilitate and enhance the gas recovery process from conventional and tight gas resources. Tight gas or unconventional reservoirs, that include very low permeability sandstones, carbonates, or shales, cannot be economically produced without hydraulic fracturing. Recently, much progress has taken place in the overall hydraulic fracturing procedures and the field implementations of advanced stimulation technology have produced good results. The proper selection of well trajectory, gel concentration, polymer loading, proppant type/size and concentration, perforation methods, locations for packer and frac port placement in a multistage fracturing assembly, number of fracture stages to cover the net pay, etc., have all contributed to successful stimulation and improved gas recovery. Even though stimulating gas reservoirs has become a routine application and much experience has been gained in this area, not all treatments are straightforward without problems and challenges. Unless a stimulation treatment is carefully designed and implemented, the post-stimulation results in moderate to tight reservoirs may not be encouraging, and can easily fall below expectation.

The most essential step to close the gap between expected results and actual well performance is to understand reservoir characteristics and its potential to produce at a sustained rate after a successful fracturing treatment. Overestimation of reservoir flow capacity and achieved fracture geometry will also over-predict well performance. This paper addresses the importance and impact of detailed reservoir characterization and superior stimulation processes on final well performance. Several field examples from Saudi Arabia’s gas reservoirs are presented in the paper showing the value of effective well planning, reservoir characterization, application of hydraulic fracturing, and proper cleanup.

The paper also illustrates the impact of drilling trajectory and wellbore reservoir connectivity on the proper placement of desired hydraulic fracture treatments and sustained gas production.
Fractures and Craters Produced in Sandstone by High-Velocity Projectiles
Authors: Rinehart John S. , Maurer William C.
Published: June 2014

The mechanics of impact crater formation in rock, particularly sandstone, has been studied, the velocity range being approximately that normally associated with oilwell gun perforators. The bullets were small steel spheres having diameters of 3/16, 9/32 and 7/16 in.; impact velocities ranged from 300 to 7.000 ft/sec. The craters have two distinct parts - a cylindrical hole (or burrow) with a diameter the same as that of the impacting sphere, and a wide-angle cup comprising most of the volume of the crater. The burrow is formed as material in front of the projectile is crushed and pushed aside, forming a cylindrical hole surrounded by a high-density zone. The cup forms as fractures are initiated in front of the projectile and propagate along logarithmic spirals, approximating maximum shear trajectories, to the free surface of the rock. A most significant observation (made for the first time) was that, below the base of the cup in one type of sandstone, there are a group of similar fractures, not extending to the surface, which are spaced uniformly a few millimeters apart. Each fracture follows roughly the contour of the base of the cup and appears to require a certain threshold impulse to initiate it. These fractures comprise a relatively high fraction of the total, newly exposed surface area. The volume of the material removed by crushing varies as the first power of the impact velocity and the volume removed by fracturing, as the second power of the impact velocity. Penetration varies linearly with the impact velocity and is inversely proportional to the specific acoustic resistance of the target material, the proportionality constant being dependent upon the shape of the projectile.
Cellar Oil
Authors: Gaskell M.H. , Lindley D.C.
Published: June 2014

Introduction

Small, steeply inclined reservoirs without natural water drives often are found associated with salt domes or other highly faulted structures. Frequently, only one well may be economically justified in these reservoirs, from which oil is produced by an expanding gas-cap drive or by a dissolved-gas drive. Although a large fraction of the oil upstructure from the well may be recovered during primary depletion, only a small fraction of the downdip oil can be produced because of gravity effects. This downdip oil has been defined as "cellar oil"' in contradistinction to "attic oil" which is the oil above the structurally highest well in reservoirs where a natural water drive is present. In this study, two methods of producing cellar oil by water flooding a one-well reservoir were investigated by means of a laboratory model. This model was scaled to represent a prototype reservoir having an area of 30 acres, a permeability of 500 md, and a thickness and dip of 30 ft and 30, respectively. One method considered, the simultaneous injection of water and production of oil from a single well, would require that the lower portion of the productive interval of a well be completed for water injection and the upper portion for oil production. The other method considered, intermittent injection, would involve alternate injection of water into and production of oil from a single well. Injection of water into the formation would repressure the reservoir, causing gas to go back into solution. Since some of the injected water would flow updip from the well, water injection usually would be followed by a waiting period during which the water could drain from above the wellbore. Production of oil by gravity drainage and gas-cap drive could be initiated when water drainage became sufficiently complete. The amount of water produced along with the oil would naturally depend on how soon after water injection ceased that production was started. This process could be repeated in cycles until oil could no longer be produced economically.

Of these two methods, the intermittent injection technique would be simpler to put into operation since it does not require a dual completion. Also, it is probably more generally applicable than the simultaneous injection-production method. It is to be expected that in some reservoirs the rock and fluid properties would be such that practical oil-production rates could not be achieved by the simultaneous technique. However, in reservoirs where the simultaneous method will result in practical rates of oil production, it does have the advantage of permitting immediate, continuous oil production; whereas in the intermittent method, oil production is interrupted by periods of water injection and drainage. It was the objective of this study to determine whether these two methods of cellar oil production are practical for the representative prototype investigated and to evaluate their relative merits.
Unsteady-State Gas Flow into Gas Wells
Authors: Smith R.V.
Published: June 2014

The theory for unsteady radial flow of gas, as simplified by Aronofsky and Jenkins, has been reviewed and compared with actual well performance. This study indicated that the theory should be modified by the introduction of an empirical "rate of flow" function "Y(q)". The expansion of the theory on the flow of gas to include a Y(q) term bridges the gap between the theory of unsteady-state flow of gas and actual gas-well behavior. Apparently, the Y(q) term is a function only of the rate of flow for a given well. The completion factor or skin effect is associated with the Y(q) function in such a manner that at least two or more sets of drawdown or pressure build-up tests are needed to separate the Y(q) function and the completion factor. Since the Y(q) function used in this report represents an energy loss dependent on rate of flow near the well-bore of a gas well which is in addition to the loss required by Darcy's law, the Y(q) function is related to the exponent of the back-pressure curve for a gas well.

Techniques and equations are presented which permit the estimation of stabilized and "short-time" deliverabilities.

Introduction

The published theory of radial unsteady-state flow of gas through porous media may be divided into papers which use Darcy's law as a premise and other papers, which recognize that Darcy's law may not hold for flow into gas wells. Miller compared theory based on Darcy's law with actual gas-well behavior and concluded that flow into gas wells deviates from Darcy's law. Houpeurt in a thorough investigation of flow into gas wells concluded that the flow rate into a gas well is proportional to the difference between the squares of upstream and downstream pressures elevated to a power between 1.0 and 0.5. Houpeurt also concluded that the deviation from Darcy's law is caused by irreversible, kinetic energy exchange between the flowing gas and the porous media. Tek presented a complete evaluation of the flow problem in gas wells. Several investigators state that the inclusion of gas compressibility into flow equations based on Darcy's law does not begin to explain the flow problems suggested by gas-well behavior.