**Current Filters**

**Peer Reviewed**

**Source**

**SPE Disciplines**

**Conference**

- Annual Technical Meeting (11)
- Offshore South East Asia Show (1)
- SPE Annual Technical Conference and Exhibition (9)
- SPE Asia Pacific Oil and Gas Conference and Exhibition (1)
- SPE Eastern Regional Meeting (1)
- SPE Gas Technology Symposium (1)
- SPE Rocky Mountain Regional Meeting (2)
- SPE Western Regional Meeting (2)

**Theme**

**Author**

- Acosta, L.G. (1)
**Ambastha, A.K. (49)**- Aziz, K. (1)
- Barman, I. (1)
- Beliveau, D.A. (1)
- Brown, M.W. (1)
- Chakrabarty, C. (1)
- Chornet, M. (1)
- Evola, G.M. (1)
- Ghaffari, K. (2)
- Gomes, E. (1)
- Gomes, Edmond (2)
- Grader, A.S. (1)
- Issaka, M. (1)
- Issaka, M.B. (6)
- Kosarussawadee, P. (1)
- Kumar, M. (3)
- lssaka, M.B. (1)
- McLeroy, P.G. (1)
- Moynihan, T.J. (1)
- Raghavan, R. (2)
- Rahman, N.M. Anisur (5)
- Rahman, N.M.A. (2)
- Rame, H.J. (1)
- Ramey, H.J. (3)
- Ramsey, H.J. (1)
- Skow, L.A. (1)
- Tang, R.W. (1)
- Wong, K.H. (2)
- Zhang, M.Y. (1)

**Concept Tag**

- Agarwal slope (2)
- analysis (15)
- artificial lift system (3)
- base case (2)
- Behavior (4)
- behaviour (3)
- boundary (10)
- boundary condition (3)
- buildup (2)
- Canadian Petroleum Technology (2)
- case (4)
- chemical flooding (7)
- coefficient (2)
- compartment (4)
- compressibility (4)
- condition (6)
- curve (3)
- data (10)
- decline (4)
- discontinuity (6)
- effect (11)
- eigenvalue (3)
- equation (14)
- falloff (3)
- Fig (7)
- Figure (13)
- Flow (15)
- flow geometry (4)
- flow in porous media (3)
- flow regime (3)
- Fluid Dynamics (11)
- formation evaluation (48)
- front (4)
- gas injection method (4)
- gas lift (3)
- gas reservoir (3)
- geometry (3)
- geothermal reservoir (9)
- Horizontal (3)
- horizontal well (6)
- injection (6)
- interface (5)
- interference (3)
- interference test (3)
- layer (3)
- line (4)
- machine learning (4)
- Material Balance (3)
- Material Balance Equation (2)
- Maximum (2)
- method (4)
- mobility (11)
- mobility ratio (4)
- model (16)
- oil (5)
- paper (7)
- performance (4)
- period (4)
- permeability (4)
- petroleum (4)
- pressure (10)
- pressure response (3)
- pressure transient testing (33)
- produced water (7)
- production control (39)
- production logging (10)
- production monitoring (39)
- pseudosteady state (3)
- PVT measurement (6)
- radial (6)
- ratio (4)
- recovery (5)
- region (18)
- reservoir (15)
- reservoir simulation (29)
- Response (18)
- result (5)
- SAGD (19)
- saturation (4)
- semilog (3)
- shale gas (7)
- simulator development (5)
- situation (3)
- skin (5)
- slope (5)
- solution (14)
- steam injection (4)
- steam-assisted gravity drainage (19)
- Storativity (2)
- storativity ratio (4)
- study (12)
- system (9)
- Table (2)
- thermal method (19)
- time (13)
- value (6)
- volume (3)
- waterflooding (7)
- well (16)
- wellbore (5)

**Industry**

**Oilfield Places**

**Technology**

**File Type**

Abstract

Cymric 1Y is a heavy oil diatomite reservoir in California, U.S.A. with an estimated original oil-in-place (OOIP) of 425 MMSTB. Diatomite reservoirs have low permeability (average of 5 md or less) and high porosity (50-60%).

The primary objective of this study was to investigate future development options using a consistent Base case for the cyclic operation in the 1Y pilot area. Field data from the in-fill pilot area, with a well spacing of 5/8-acre, and a fine-grid simulation of a four-well segment was used in this study.

Results show that fine grids (of the order of one ft), perpendicular to the steam-induced fracture orientation, are necessary to properly capture the effects of sharp temperature and saturation gradients in the primary fluid flow direction. Initial saturation, reservoir matrix permeability, fracture half-length, capillary pressure, and flowing bottom-hole pressure were identified as key parameters at Cymric 1Y.

Results also show that the cyclic steam development at 5/8-acre may result in 22% recovery. Infilling to 5/16-acre spacing could increase the recovery to 34% OOIP. Success of steam drive at Cymric 1Y would require that fractures remain open at both injectors and producers. A successful steam drive could further boost the ultimate recovery.

Background

Production at Cymric 1Y occurs from the upper portion of the upper Miocene Antelope Shale of the Monterey Group. Exploitation strategy for this reservoir is based on short steam cycles with steam injection above fracture pressure for 3-6 days. Steam injection causes a vertical fracture to develop at the well. After steam injection, well is allowed to soak for 3-4 days. During the soak period, steam and condensed hot water further propagate into the reservoir. Well is then allowed to produce under self-flowing conditions for 15-25 days. Viscosity reduction and capillary imbibition are the primary recovery mechanisms for Cymric 1Y. Also, steam-assisted lift occurs during the production cycle. A typical cycle lasts for about a month or less. Currently, Cymric 1Y produces at over 20,000 STB/day with a steam/oil ratio of 2-2.5.

In the past, a single-well, layer-cake, cyclic steam model for Cymric 1Y diatomite reservoir operating under fracturing conditions was developed by Kumar and Beatty^{1}. This paper outlined most of the rock and fluid parameters that have been used for all subsequent Cymric 1Y simulation studies at Chevron, including this study. This paper also established the need for fine gridblocks in the direction perpendicular to the fracture to capture the effects of sharp saturation and temperature gradients that occur away from the fracture face in Cymric 1Y cyclic steam operation.

Using a detailed geostatistical model of the pilot area incorporating core and log data from 63 wells, Fong *et al*.^{2,3} describe the development of a coarse-grid reservoir simulation model for four patterns surrounding wells 2112R, 2212S, 2113S and 2213S (**Fig. 1**). This model covered 11 wells in the pilot area and was intended to develop an understanding of well-to-well interference effects for long-term operations under cyclic steam or steamdrive operations. This model will be referred to as the Coarse Grid Model (CGM) throughout this paper.

To address competing requirements for fine grids and multi-well models, this study has used the CGM geostatistical model to extract a reservoir simulation model for a four-well segment within the pilot area. The current model uses fine grids away from the fracture to capture the effects of sharp temperature and saturation gradients. This model also allows for an infill well. Thus, we can study well-to-well interference effects, and future cyclic steam and steam drive scenarios using the model presented in this study.

base case, case, constraint, formation evaluation, fracture, geomechanics, injection, model, oil, operation, permeability, pressure, producer, production control, production monitoring, recovery, reservoir simulation, result, SAGD, saturation, scaling method, Steam Operation, steam-assisted gravity drainage, temperature, thermal method, wellbore integrity

Oilfield Places:

- North America > United States > California > Cymric Field (0.99)
- South America > Brazil > Acre Basin (0.98)
- North America > United States > North Dakota > Antelope Field (0.98)

SPE Disciplines:

**Summary **

A new generalized transient-flow model for a three-dimensional (3D) compartmentalized system with n compartments has been developed analytically. Each compartment may have distinct rock and fluid properties and may produce through a number of partially penetrating wells. A partially communicating fault or barrier causing poor hydraulic communication between a pair of adjoining compartments is modeled as a thin skin at the interface. Production rates and conditions at the extreme boundaries are considered to be time variant. The solution was also validated by examining a few limiting cases. An example problem with stacked channel realization was studied. A simple method for detecting the poorly drained compartments from the extended drawdown data was developed. This has also lead to an estimation of hydrocarbon-pore volume in each compartment.

**Introduction **

Compartmentalized reservoirs are made up of a number of hydraulically communicating compartments or regions. The communication of fluid between the adjoining compartments may be poor due to the presence of faults or low-permeability barriers. Evidence of reservoir compartmentalization both in oil and gas reservoirs has been presented in the literature.^{1} The idea of compartmentalization was developed initially from observations of discontinuities of pressures in producing fields.^{2} Reservoir compartmentalization has been observed in both areal and vertical extent. The horizontal barriers may be due to the presence of shales, micaceous streaks or stylolites while the vertical barriers may be due to the presence of faults or stratigraphic changes.^{2} In the mathematical models^{3,4} for transient flow in areally compartmentalized reservoirs, the effects of gravity are neglected. However, in the presence of massive vertical compartmentalization, such effects are important. Rahman and Ambastha^{5} have used the solution from another study^{4} to evaluate the communication resistance between a system of a small compartment (producing) in communication with a big compartment (supporting) from extended drawdown data.

A number of models based on the material balance technique has been proposed in the literature for studying compartmentalized reservoirs.^{2,6,7} However, these models work reasonably well for gas reservoirs having permeabilities in the range of moderate to high (greater than 5 md).^{8} Lord *et al.* also concluded that these material balance models are not appropriate for formation permeabilities less than 5 md. Thus, the criterion for using such models will be much more restrictive for oil reservoirs.^{5} The rate of fluid crossing the interface boundary between a pair of adjoining compartments in these studies is dependent upon the barrier transmissibility and the difference between the average compartment pressures (or potentials), neglecting the internal resistance to fluid communication within the compartments. So specifying low values to barrier transmissibility has been a means by which to simulate the poor communication between the compartments. Stewart and Whaballa^{2} and Fox *et al.*^{6} considered the material balance equations for a single-phase fluid in terms of compartment volumes, interblock-transmissibility indices and average compartment pressures. Ehlig-Economides^{7} presented the multiphase material balance equations involving the flow of oil, water and gas.

In the development of an analytical solution for transient flow in this work, the resistance to fluid communication between any two neighboring compartments is specified by a skin factor to take into account the poor hydraulic communication between these compartments following the ideas of van Everdingen^{ 9} and of Hurst.^{10} The rate of fluid crossing an interface boundary is dependent upon the value of the skin factor and the difference between the potentials across the thin skin at the interface. Partial differential equations with appropriate initial and boundary conditions are set up starting from the diffusivity equations describing 3D flow through porous media. Due to the possible importance of gravity, especially with compartmentalization in vertical extent, the governing equations need to be considered in terms of potential instead of pressure.^{7} Hubbert^{ 11} described the force potential as the energy per unit mass. However, in this study, the potential as the energy per unit volume is considered. The transient potential. ?(*x,y,z,t*) is defined at a point, (*x, y, z* ), in a Cartesian coordinate system, within the domain under consideration, as \Phi (x,y,z,t)=p(x,y,z,t) - \rho gz,\eqno ({\rm 1}) where *p*(*x,y,z,t* ) is the transient pressure at the point (*x, y, z*), at time *t*, and *z* is the distance from a reference plane (*x-y* plane as in this case) which is taken as positive in the direction of gravity. A similar approach with potential was also taken by Collins^{12} for formulating Darcy's equation for incompressible flow and by Papatzacos^{13} for formulating an analytical model for a partially penetrating well. However, neglecting the effects of gravity in the solution will transform the solution with potential into that with pressure and this can be done simply by replacing potential with pressure.

**Development of Analytical Solution **

In the following subsections, the development of an analytical solution is discussed.

Ambastha, boundary, communication, compartment, condition, eigenvalue, equation, Flow, formation evaluation, interface, ith compartment, model, potential, pressure transient testing, problem, produced water, production control, production logging, production monitoring, Rahman, reservoir, reservoir simulation, respectively, shale gas, solution, system

Pressure derivatives have been shown to be more sensitive to disturbances in the reservoir than pressure signals; resulting in more detail on derivative graphs than is apparent on pressure graphs. The semilog pressure derivative is widely used in well test analysis. One reason for its popularity is that, for radial systems, the response appears as a horizontal line during the infinite- acting radial flow period, resulting in easier identification. However, when the semilog pressure derivative is applied to flow geometries other than radial, the responses are not horizontal; making identification of flow regimes more difficult. Thus, a generalized pressure derivative is necessary to simplify the identification of flow regimes in any flow geometry.

In this study, a generalized pressure derivative is defined and used to identify the various flow regimes for composite systems in radial, elliptical, linear and spherical geometries. This generalized pressure derivative is of the power law type, and is characterized by a different exponent for each of the flow geometries. Using well test data from analytical solutions for radial, elliptical, linear and spherical composite reservoirs, a graph of the generalized pressure derivative versus time, for any of the flow geometries appears as a horizontal line during the primary flow regime characteristic of that geometry.

Design and analysis equations, based on the generalized pressure derivative, are presented for well testing of composite reservoirs in various flow geometries. Reservoir parameters estimated using these equations will add to the degree of confidence in the estimated parameters based on pressure analysis. The generalized pressure derivative is also used to investigate differences and similarities among the four flow systems. Results from this study confirm that for radial and elliptical systems, the long term pressure derivative behaviour is influenced only by the mobility ratio between the inner and outer regions of the composite system. For linear and spherical systems, however, long term derivative behaviour is governed by both the mobility ratio and the storativity ratio. This finding has a significant impact on the development of type curves for either manual or automated type curve matching for the various flow geometries.

doi: 10.2118/99-13-57

PETSOC-99-13-57

analysis, chemical flooding, derivative, equation, Figure, Flow, flow geometry, formation evaluation, geometry, mobility, mobility ratio, pressure transient testing, production control, production logging, production monitoring, radial, ratio, region, reservoir simulation, Response, SAGD, steam-assisted gravity drainage, storativity ratio, thermal method, time, transition, value

Oilfield Places:

- North America > United States > Texas > Chevron Oil Field (0.99)
- North America > Canada > Saskatchewan > Alberta Basin (0.98)
- North America > Canada > Manitoba > Alberta Basin (0.98)
- (2 more...)

Fluid flow in narrow reservoirs or aquifers is predominately linear. However, this linear-flow system may possess variations in rock and fluid properties and/or presence of faults due to a number of geological phenomena. Such systems are modelled as linear, compartmentalized systems.

In this study, a new generalized transient-flow model has been developed analytically for an n-region compartmentalized system. Each compartment or region may have distinct rock and fluid properties. A time-dependent production rate from each compartment is modelled in a general way. The conditions at the extreme boundaries are taken as non-homogeneous, time-dependent, Cauchy-type that can be modified to Dirichlet- or Neumann-type as a special case. A possible situation of poor communication between neighboring compartments has been incorporated into the model by considering the presence of a thin skin at each interface. A generalized solution for the dimensionless pressure has been derived using an integral-transform technique.

This solution deals directly with situations like production rates and extreme boundary conditions being time-dependent without the need for using the principle of superposition in time or Duhamel's principle. Some limiting cases of this new solution have been used for validation purposes. Several advantages and practical applications of this model are also discussed.

doi: 10.2118/99-13-53

PETSOC-99-13-53

boundary, boundary condition, coefficient, compartment, condition, differential equation, eigenvalue, equation, Figure, Flow, formation evaluation, function, interface, mth compartment, pressure transient testing, production control, production monitoring, reservoir simulation, skin, solution, study, system

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3-6 October 1999.

base case, case, combustion, combustion tube, correlation, Figure, formation evaluation, gas injection method, laboratory, model, oil, oil production, performance, production control, production monitoring, reaction, reservoir simulation, result, SAGD, saturation, scaling method, simulator development, steam-assisted gravity drainage, temperature, thermal method, viscosity

Oilfield Places:

- North America > United States > California > San Joaquin Valley > San Joaquin Basin > South Belridge Oil Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Valley > San Joaquin Basin > South Belridge Oil Field > Diatomite Formation (0.99)
- North America > United States > California > Midway-Sunset Oil Field (0.99)
- Europe > Czech Republic > Most Basin (0.94)

SPE Disciplines:

A mathematical model is developed in order to evaluate the productivity ofmultilateral completions. The model may also be used to understand and discernthe pressure behaviour of multilateral completions. The ability to incorporatethe location of each lateral rigorously is the unique feature of the model. Asa result of the development of this model, it is now possible to calculaterapidly the efficacy of various options and to incorporate this completionscheme in numerical models to evaluate the possible influences of interference,boundaries, changes in reservoir properties, etc.

doi: 10.2118/98-10-05

PETSOC-98-10-05

SPE Disciplines:

Analysis of production decline curves presents a useful tool in forecasting the future production from a well or reservoir. A knowledge of the future production is an important factor in the economic analysis of exploration and production expenditures. Decline curve analysis can be used to estimate the production performance of a stimulated well due to acidizing. A comparison of the production decline before and after acid treatment will enable a determination of the technical and economic success of the treatment.

Decline curve analysis for homogeneous reservoirs has been discussed extensively in the literature. However, the conventional homogeneous decline type curves are not appropriate for composite reservoirs. While production decline curves for radial, composite reservoirs have been presented, the same is not the case for composite reservoirs in elliptical, linear and spherical flow geometries.

This study presents a comparison of the production performances of two-region, composite reservoirs in radial, elliptical, linear and spherical flow geometries. Transient rate and cumulative production responses for both infinite and closed, finite reservoirs for the various flow geometries are discussed. Normalizing factors are presented to enable comparison of production rate and cumulative production responses for the various composite reservoirs. A detailed investigation of the effects of mobility and storativity ratios, and also, the reservoir size on the production rate and cumulative production responses from radial and linear, composite reservoirs are presented.

Results from this study show that the mobility-storativity product, MF, is not a correlating parameter for transient rate and cumulative production responses from finite, linear, composite reservoirs, unlike the case for infinitely large, linear, composite reservoirs. Some type curves for decline curve analysis of radial and linear composite reservoirs are presented.

doi: 10.2118/98-06-01

PETSOC-98-06-01

Oilfield Places:

- North America > United States > Texas > Chevron Oil Field (0.99)
- North America > Canada > Saskatchewan > Alberta Basin (0.98)
- North America > Canada > Manitoba > Alberta Basin (0.98)
- (2 more...)

Abstract

Pincher Creek gas field, located in south-western region of Alberta, was discovered in 1947 by Canadian Gulf Oil. Pincher Creek gas field is a low-permeability, naturally- fractured, carbonate reservoir. Production from this field started in Jan. 1957. A total of 27 wells have been drilled in this field. However, only six wells are still producing from this reservoir. Many wells in this field have experienced shortened producing life because of water-related problems.

Initial gas-in-place and remaining reserves are reported as 46.8 and 1.5 BCM, respectively, in Alberta Energy and Utilities Board (AEUB) 1994 publication of reserves. Cumulative gas production to the end of Dec. 1996 has been 14.5 BCM. Thus, Pincher Creek gas field seems to have a very low recovery factor. Forty years of production data have been analyzed using conventional material balance, decline curve analysis, and communicating reservoir model to verify initial gas-in- place and reserve estimates for the Pincher Creek gas field. These analyses have led to definitive and consistent initial gas- in-place and reserve estimates for this field.

Efforts have also been made to understand water production mechanisms in this field. Analysis shows that water production behavior in this field is neither related to permeability distribution from core analysis nor to the distance from the bottom of perforation to gas-water contact. Diagnostic plots of the Cartesian derivative of water-gas ratio versus time have shown promise in identifying water production mechanisms for the wells in this field.

P. 367

analysis, CNG, compressed natural gas, condensate reservoir, Creek, data, decline, field, Fig, formation evaluation, gas monetization, Material Balance, Pincher, Pincher Creek, Pincher Creek field, Pincher Creek gas field, pressure, produced water, production, production control, production monitoring, reserve, reservoir simulation, shale gas, water production, well

Oilfield Places:

- North America > Canada > Alberta > Pincher Creek Gas Field (0.99)
- North America > Canada > Saskatchewan > Alberta Basin (0.91)
- North America > Canada > Manitoba > Alberta Basin (0.91)
- (2 more...)

SPE Disciplines:

Horizontal wells have become quite popular for primary and enhanced oil recovery operations due to their well-documented advantages over vertical wells. Steam injection through horizontal wells has also been attempted at several places to improve heavy oil recovery. For horizontal wells undergoing steam injection, a steam chamber containing high mobility steam is established. This steam chamber, which can be of a complex shape, is surrounded by low mobility reservoir fluids. Such reservoir situations are referred to as composite reservoirs. An analytical solution for pressure transient tests for horizontal wells under composite reservoir situations with complex swept region shapes is not available yet.

This study attempts a numerical investigation of pressure transient analysis for horizontal wells in two-region, composite reservoirs mimicking thermal recovery situations. A specialized three-dimensional, single-phase simulator was developed for this purpose. A closed, box-shaped reservoir was considered with a horizontal well.

A detailed sensitivity study of transient pressure responses is presented with respect to grid size, well location in different directions, swept region shape, mobility ratio and storativity ratio. This study emphasizes the effects of the aforementioned factors on the swept volume estimation using the pseudosteadystate method. The pseudosteady-state method is based on an analysis of a Cartesian graph of pressure response versus time. This study establishes that for horizontal wells, the swept (or inner) region volume in a two-region system can be accurately estimated by the pseudosteady-state method for large mobility and storativity contrasts between the two regions.

doi: 10.2118/98-03-01

PETSOC-98-03-01

analysis, Cartesian, effect, Figure, formation evaluation, grid, horizontal well, mobility, petroleum, pressure transient testing, production control, production logging, production monitoring, region, region shape, reservoir simulation, Response, result, SAGD, simulator development, steam-assisted gravity drainage, study, thermal method, value, volume, well, wellbore

Material balance calculations for gas-condensate reservoirs with reservoir pressures below the dew-point pressure require the use of two-phase deviation factor to account for the phase behaviour effects of a gas-condensate fluid. Recently, an empirical correlation for the two-phase deviation factor has also been presented in the literature.

In this study, a phase behaviour package based on the Redlich-Kwong equation of state as modified by Zudkevitch and Joffe has been used to investigate some of the issues in connection with the application of two-phase deviation factor to material balance calculations for gas-condensate reservoirs.

This study shows that the two-phase deviation factor does not necessarily increase in the two-phase region as the pressure increases, whereas the empirical correlation shows that the twophase deviation factor always increases with pressure. A study has also been carried out to quantify the errors in estimating the initial gas-in-place due to input data errors, fluid composition effects, computation methodology for deviation factor, and the use of improper deviation factor.

doi: 10.2118/98-02-05

PETSOC-98-02-05

SPE Disciplines: