**Peer Reviewed**

**Source**

**Journal**

**Conference**

- 1994 SEG Annual Meeting (2)
- 1997 SEG Annual Meeting (1)
- Abu Dhabi International Petroleum Exhibition and Conference (1)
- European 3-D Reservoir Modelling Conference (1)
- European Petroleum Conference (1)
- SPE Annual Technical Conference and Exhibition (6)
- SPE Asia Pacific Conference on Integrated Modelling for Asset Management (1)
- SPE Asia Pacific Oil and Gas Conference and Exhibition (1)
- SPE India Oil and Gas Conference and Exhibition (1)
- SPE International Oil and Gas Conference and Exhibition in China (3)
- SPE Latin American and Caribbean Petroleum Engineering Conference (1)
- SPE Petroleum Computer Conference (1)
- SPE Production Operations Symposium (1)
- SPE Reservoir Simulation Symposium (5)
- SPE Western Regional Meeting (1)
- SPWLA 36th Annual Logging Symposium (1)
- SPWLA 37th Annual Logging Symposium (1)

**Publisher**

**Theme**

**Author**

- Al-Haddad, S. (1)
- Andersen, M.A. (2)
- Arbaugh, R. (1)
- Arceneaux, C.L. (1)
- Ariffin, Tajjul (1)
- Bahorich, Mike (1)
- Baksi, William F. (1)
- Bard, Wade (1)
- Barkve, T. (1)
- Barua, Santanu (1)
- Berge, J. (1)
- Bowen, G.R. (2)
- Boyd, Austin (1)
- Brady, J.L. (1)
- Bratvedt, F. (1)
- Buffington, L. (2)
- Bøe, Ø. (1)
- Chalupsky, G.F. (1)
- Chatterjee, D. (1)
- Childs, P. (1)
- Colson, J.L. (1)
- Cook, C.C. (2)
- Corbett, C. (2)
- Corbett, Chip (2)
- Cox, J. (2)
- Ehlig-Economides, C.A. (1)
- Esmersoy, Cengiz (1)
- Febvre, F. (1)
- Finley, Robert J. (1)
- Fjerstad, Paul (3)
- Flynn, J. (1)
- Garcia, Steven A. (1)
- Gislefoss, E. (2)
- Gunasekera, D. (2)
- Halle, G. (2)
- Hallford, Debora L. (1)
- Hattori, Masami (1)
- Hebert, J. (1)
- Hegeman, Peter S. (1)
- Hepguler, Gokhan (1)
- Herring, J. (1)
- Holmes, J.A. (1)
- Hook, Peter (4)
- Hoskins, Josiah (1)
- Ingebrigtsen, L. (1)
- Kane, Michael (1)
- Kleinberg, R.L. (1)
- Koster, Klaas (1)
- Kuchuk, Fikri J. (4)
- Lenn, Chris (4)
- Lindsey, P. (1)
- Logan, D. (1)
- Lovell, J.R. (1)
- Lovell, John R. (1)
- Lund, O. (1)
- Mantran, Pascal (1)
- May, Ed (1)
- McKnight, D. (1)
- Mijares, O. (1)
- Moinard, L. (1)
- Moore, David M. (1)
- Morriss, C.E. (1)
- Mowat, G.R. (1)
- Munoz, P. (1)
- Naccache, P.F. (1)
- North, R.J. (1)
- Pepper, Randy (1)
- Plato, I.S. (1)
- Querin, E. Mark (1)
- Ramonez, M. (1)
- Reiso, E. (1)
- Romero, M. (1)
- Rosthal, R.A. (2)
- Rounce, Justin (1)
- Rusdinadar, Sigit (1)
- Schultz, P.S. (1)
- Sezginer, A. (1)
- Shehata, M. Taher I. (1)
- Solomon, G.J. (1)
- Sommer, D.M. (1)
- Sonrexa, Kartikay (1)
- Trayner, P.M. (1)
- Ujang, Salehudin (1)
- Van Bemmel, Peter (2)
- Waite, Mike (1)
- Walker, Charles W. (1)
- Warner, D.W. (1)
- Watson, B.A. (1)
- Williams, Marty (1)
- Williams, R. (1)
- Wolcott, D.S. (1)
- Young, R.A. (2)

**Concept Tag**

- Abu Dhabi (1)
- Adnoc (1)
- ADNOC Group (1)
- analysis (5)
- application (4)
- approach (2)
- April (1)
- Artificial Intelligence (5)
- azimuthal (2)
- boundary (2)
- branch (2)
- cell (2)
- change (2)
- company (2)
- completion (2)
- condition (2)
- database (2)
- decision (2)
- Delaware (1)
- dip (2)
- Dipole Shear (1)
- Directional Drilling (2)
- distribution (6)
- Drilling (2)
- drilling operation (2)
- Drillstem Testing (5)
- drillstem/well testing (5)
- Dulang West (1)
- Dulang West field (1)
- effect (2)
- Engineer (2)
- enhanced recovery (3)
- entry (2)
- Expris (1)
- field (4)
- Fluid Dynamics (4)
- formation evaluation (16)
- GeoQuest (1)
- grid (3)
- holdup (3)
- horizon (2)
- Horizontal (4)
- horizontal well (8)
- image (2)
- increase (2)
- Industry (1)
- information management (3)
- interpretation (7)
- knowledge management (2)
- layer (2)
- log (3)
- log analysis (6)
- log property (2)
- LWD resistivity (1)
- management and information (3)
- map (2)
- model (8)
- paper (4)
- Performance Evaluation (3)
- permeability (7)
- petroleum (2)
- porosity (2)
- Probe (2)
- production (8)
- production control (5)
- production logging (5)
- production monitoring (5)
- productivity (5)
- property (4)
- RAB (2)
- RAB image (2)
- reflection (2)
- relationship (2)
- reservoir (3)
- Reservoir Characterization (13)
- reservoir description and dynamics (32)
- reservoir simulation (9)
- Reservoir Surveillance (5)
- resistivity (2)
- seismic processing and interpretation (8)
- Sigma (2)
- Simulation (3)
- simulator (2)
- society of petroleum engineers (4)
- solution (2)
- streamline (2)
- study (3)
- system (3)
- technology (2)
- test (2)
- tool (9)
- Upstream Oil & Gas (33)
- water (10)
- water saturation (3)
- water-induced compaction (2)
- waterflooding (3)
- well (16)
- well logging (6)
- well path (2)
- wellbore (7)

**File Type**

This paper presents two different and simple methods of tracking water rise in a gas reservoir. From the case study of a complex multi-layered sand reservoir of Indonesia, it shows how the two independent approaches were validated, and generalised to other similar reservoirs. The objective is to control the water production, thus extending the life of reservoirs with an active aquifer.

The first method is based on material balance coupled with 3D mapping. The paper shows how water influx which is initially calculated from history match of the material balance, can then be converted into water rise. This approach can be easily implemented on a spreadsheet with some basic input from the geological maps of the reservoir, without the need for any heavy 3D reservoir simulation. Once water rise is calculated, the paper goes on to describe how it can simply be predicted.

The second method is based on reservoir saturation logging. The paper details step by step, the procedure that was elaborated to get direct in situ measurement that could be exploitable despite a complex environment in an ageing field. It describes how the combination of different recorded parameters can reduce the uncertainty from the raw measurement. It also highlights recommendation that were drawn from initial unsuccessful attempts to log through two strings of pipe.

This paper shows how these two methods were validated on the same reservoir when a new well was drilled and tagged the new water contact at the predicted depth.

**A. Material Balance Method**

*P/Z with aquifer model*

Material balance is a very good way to characterize the behavior of a reservoir based only on production and pressure data. Even-though it is a simplistic approach, it can be very reliable when applied to a reservoir with fairly homogeneous characteristics.

In the case of a dry gas reservoir with a known deviation factor, the material balance can be modeled by the P/Z equation as modified for water influx. The form of the simplified equation is:

Equation

Where P, P_{i} and Z, Z_{ i} are the current and initial pressures (psia) and gas deviation factors, respectively. G_{p} is the cumulative gas produced (MMscf), IGIP the initial gas in place (MMscf) and PVI the volume of water influx expressed as a fraction of the original pore volume. Water and rock compressibilities are ignored.

Based on this equation, the calculated reservoir pressure can be represented against time, to be compared with the actual measured pressure from RFT or PBU. An example is presented in Fig.1 with the reservoir depletion matched initially gas production, and finally with the aquifer support.

SPE Disciplines: Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)

Overview - No abstract available.

SPE-0401-0074-JPT

April, cell, conventional simulator, distribution, Engineer, exist, GeoQuest, grid, increase, Modeling & Simulation, Overview, product, property, recovery, Reservoir Characterization, reservoir description and dynamics, reservoir simulation, Simulation, simulation engineer, streamline, technology, Upstream Oil & Gas

SPE Disciplines:

Cook, C.C. (Amerada Hess Norge AS) | Andersen, M.A. (Amoco Norway Oil Co.) | Halle, G. (Elf Petroleum Norge AS) | Gislefoss, E. (Enterprise Oil Norge Ltd.) | Bowen, G.R. (GeoQuest)

**Summary**

Rock-compaction drive under waterflood re-pressurization has not been accounted for previously in our flow-model studies for a Valhall waterflood. However, field observations from pilot waterfloods indicate an increase in permeability with the injection of cool seawater into the chalk formation. Platform subsidence measurements taken during the pilot waterflood also provide evidence of a chalk/water interaction. Laboratory experiments on reservoir core samples indicate an accelerated compaction effect as the flood front passes through the sample. To assess the value of a large-scale waterflood at Valhall, we have developed a new approach to simulate the possible effects of water-induced rock compaction in our black-oil flow models.

Oilfield Places:

- Europe > Norway > North Sea > Central North Sea > Block 7/11 > Ekofisk Field > Tor Chalk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Block 7/11 > Ekofisk Field > Ekofisk Chalk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Block 2/8 > Valhall Field > Tor Formation (0.99)
- (17 more...)

SPE Disciplines: Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)

Abstract

This paper presents the results of the numerical simulation model of the highly faulted reservoir C40/44 located in the West Flank, Block I, Lake Maracaibo western Venezuela. Based on an Integrated Approach study^{1}, the 3D dynamic model allowed to evaluate the impact of the sealing character of the inverse faults and their potential influences in the migration and fluid distribution across the faults, and consequently, the grade of difficulty in the adjustment of the historical production subjected to the water injection influence from Dic/71.

In spite of the simulation model is highly sensitive to the changes of the reservoir parameters, it is considered that the feasibility grade of the model is enough (85%), to understand the relative movement of the fluids for blocks, to quantify with certainty the recurrent remaining reserves and to identify the field development opportunities and exploitation.

Introduction

The study area is located within Block I on the west flank of the Icotea Fault in the north-central portion of Lake Maracaibo in Zulia State, western Venezuela. The sands C4, which belong to the Misoa C Formation, were deposited during the Eocene. The C Sands are about 2500 feet thick and were deposited in fluvial-deltaic to shallow-marine environments.

In 1996 was initiated an integrated reservoir study covering all the production zones of the field. One of the main results from that study was the new structural pattern of the area. This interpretation trends to compartamentalize the reservoir in 3 bigger blocks.

The C-4 reservoir of the V-31 area has been produced since December 1959, when the well V-316 flowed. It is basically a heterogeneous multi-layer reservoir, which has been producing commingled. It is composed of seven units, from C-40 to C-46. The C-42 and C-43 units have the best petrophysical characteristics while the C-45 and C-46 units have the worst.

This mature reservoir produces an average API oil gravity of 31 . Its initial pressure was 3500 psi at a datum of 7500 . The bubble pressure was estimated in 2300 psi, which indicated that the oil in the reservoir was above bubble point. Currently, the mechanism of production of the reservoir is a combination of water injection and water influx. Due to geological complexities, which were not detected in the past, there is little efficiency in the maintenance of pressure due to water injection, which was started in Dic/71. . Several water injector wells have been added to improve the performance of the water injection project.

The daily production from the field is 2854 bbl/d with an average water cut of 29 percent and a GOR of 802 scf/bbl (March 1999) using 13 wells. Cummulative production has been 62.5 MMbl of oil, 60.5 MMMscf of gas and 18.1 MMbl s of water, until March 1999.

This reservoir has been under the influence of an extensive aquifer, which seems to have a moderate activity, as indicated by the pressure history and water production history of the wells.

A reservoir simulation study was based on the static model derived from the integrated study. The objectives of the study were to provide a more realist estimated of remaining reserves to explore field development opportunities and to improve production potential of the area under study.

approach, block, enhanced recovery, fault, field, Lake Maracaibo, model, numerical simulation model, paper, production, Reservoir Characterization, reservoir description and dynamics, reservoir simulation, society of petroleum engineers, SPE, study, Upstream Oil & Gas, water injection, waterflooding, well

SPE Disciplines:

Abstract

This paper is concerned with the problems of real time reservoir management, simulation while drilling and near well bore modeling. These problems are discussed in terms of work process, feasibility as well as numerical and simulation related aspects. A software tool developed to perform high precision local simulation and at the same time account for global field behaviour is described. Field examples are presented to illustrate the potential and use for simulation while drilling exercises.

Introduction

Over the last 10-15 years the petroleum industry has, as all industries, constantly faced, derived and implemented new technologies. It is fair to say that the major breakthrough has been in drilling, and some examples are drilling of advanced wells, intelligent wells with remote zone control, drilling speed improvement due to drilling systems such as Autotrak and drilling bits with extended lifetime. These factors have made optimal well location and completion designs a challenging problem.

At the same time, R&D in other disciplines has led to improvements in seismic methods and 3D reservoir modeling methods to mention a few. Also, technology push on other areas has presented the industry with advanced visualization concepts, the possibility to use high speed data networks between main office and onshore and offshore sites and, of course, the use of internet as an information database.

The challenge is now to take advantage of the new technology and to optimize existing work processes. The cost and risk associated with drilling a new well is so high that all possible information and tools should be used to optimize well location.

Real time well planning is a fight against time, as drilling speed is one of the technologies that are under constant improvement. Another challenge is how to interpret the new data, sort out the important new information and use it in an optimal way. In this respect, efficient and reliable computer tools are needed.

Time is a key factor for decision while drilling, and the time frame to disposal for the decision makers may be quite different, dependent upon the situation. If a pilot hole is drilled, one has in the order of 1-3 days to use the new data and optimize the final well location and trajectory. If a multilateral is drilled, one has maybe 1-2 weeks to optimize the second branch based on data from the first. The most challenging problem is to modify (geostear) the well trajectory as the well is drilled. Within the area of reservoir simulation, this challenge is often referred to as *simulation while drilling* (SIWD). We will define simulation while drilling as any computer model based software that may help to optimize the problem together with the work process of actually performing these operations and calculations (i.e. data interpretation, model updating and simulation).

The work presented in this paper started out in 1997 as a development project between BP (now BP/Amoco), Schlumberger GeoQuest, Norsk Hydro and Saudi Aramco. The idea was to develop a software tool for modeling of near well bore phenomena^{4} to aid the design of optimal well location and completions. To our knowledge, there are few papers in the petroleum literature about simulation while drilling. In an ongoing research programme^{5} at Stanford University (Supri-B program) both analytical and numerical approaches will be considered. A semi-analytical solution that accounts approximately for reservoir heterogeneity will be considered as a base for SIWD in the first part of the project. In the second part of the project, the idea is to use SIWD with a numerical simulator. Experience with using PC-based reservoir modeling tools on-site is described and studied by Buchwalter et. al.^{6}

Abstract

Two methods for calculation of three-phase compressible flow in a porous media using streamlines are presented. For simplicity, gravity and capillary effects are neglected.

Introduction

Various aspects of streamline computations have been reported in a number of recent papers. A review of the technique was given by King et.al.[7]. As many other authors [5][9][13], he emphasis on incompressible two-phase flow. Lately, however there have been a few contributions to the field addressing compressible flow [3][10].

In this paper, we consider three-phase compressible flow. The reason why compressibility has been neglected by most authors in the field, is that it represent a strong coupling between the pressure and the saturation equations. In a streamline method, the pressure is calculated first and defines the streamlines. The saturations are then propagated along those streamlines. To obtain a stable solution using an explicit finite difference method (FDM), there is a strong limitation on the time step length. Thus, it is crucial for the efficiency of the streamline method to establish a time stepping sequence where only a small number of pressure updates is needed compared to the number of time steps required by the saturation solver. While this has been done successfully for years for incompressible flow [4], it is still a challenge to obtain both accuracy and efficiency for compressible flow.

We present two different approaches to handle the couplings between pressure and saturation. First, we describe a sequential IMPES type method, where we do additional steps for reducing the mass discrepancy error. Then an implicit method for both pressure and saturation along the streamlines is presented. The results are compared to the solutions obtained using an existing black-oil simulator.

The Governing Equations

Consider three-phase compressible flow in a porous media. For simplicity, the effects of gravity are neglected. Gravity can be accounted for using operator splitting [5] and introducing solvers for three-phase flow along gravity lines. This work is in progress, but will not be the issue of this paper. Also, capillary forces are neglected, since physical effects transverse to streamlines complicates the streamline approach.

We will study a black-oil model, with three phases and three components. We will allow gas to dissolve in the oil phase while we assume the water and gas phase to consist of only water and gas respectively. The component conservation equations now read [11] $$\eqalign {& {\matrix {{\partial \over \partial t}{\left( {\phi S wb w} \right)+\nabla \cdot \left( {b wf w \vec {v} t} \right)=q w}\cr &{ {\partial \over \partial t}} {\left( {\phi S ob o} \right)+\nabla \cdot \left( {b of o \vec {v} t} \right)=q o} }}\cr &\eqalign{{\partial \over \partial t} {\left( {\phi \left( {S gb g+R sS ob o} \right)} \right)+\nabla \cdot \left( {b gf g \vec {v} t+R sb of o \vec {v} t} \right)=q g}\cr}} \eqno (1)$$ for water, oil and gas respectively.

By summing up the component conservation equations, we obtain the pressure equation $$c t {\partial P \over \partial t} + \nabla \cdot \vec {v} t = Q- \vec {b}\cdot \nabla P\eqno (2)$$ where $$\vec {v} t = \lambda t \nabla P \eqno (3)$$is the Darcy velocity.

Refer to the nomenclature for an explanation on notation.

SPE Disciplines:

This paper was prepared for presentation at the 8th Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, U.A.E., 11-14 October 1998.

distribution, entry, formation evaluation, holdup, horizontal well, interpretation, Performance Evaluation, permeability, Probe, production control, production logging, production monitoring, productivity, reservoir description and dynamics, Reservoir Surveillance, test, tool, Upstream Oil & Gas, water, well, wellbore

Oilfield Places:

- Europe > United Kingdom > Dorset > Wytch Farm Field (0.99)
- Asia > Middle East > Oman > Dhofar Province > Marmul Field > Al-Qalata Reservoir (0.99)

SPE Disciplines:

Abstract

In this paper, the use of various measurements for performance evaluation of horizontal wells is presented. First, determining formation pressure and permeability distributions along the wellbore by using the Multiprobe Formation Tester Packer-Probe Module pressure transient interval tests are investigated. It is shown that reservoir pressure measurements along the wellbore give local as well as reservoir scale information about how the reservoir is being depleted and how cleanup takes place. A few interval pressure transient test examples are presented for both formation pressure and permeability distributions. Second, a horizontal well test interpretation is presented utilizing two buildup tests from the same well conducted at different times. It is shown that uniquely determining the reservoir parameters from short buildup tests is impossible. It is also shown that minimizing the wellbore storage effect is crucial for system identification as well as for parameter estimation. Third, the productivity of horizontal wells is explored because it has been difficult to determine the horizontal well productivity due to their long length in the formation compared with vertical wells and inadequacy of measurements during drilling and production. Using field examples, we show that the new integrated production logging measurements can be used to assess horizontal well productivity by identifying productive zones, fluid entries, and determining the fluid distribution (oil, gas, and water) in the wellbore. We also show how reservoir heterogeneity affects the reservoir pressure distribution. The field examples indicate that horizontal wells have permanent water sumps, regardless of whether they produce water. In these wells, we show that when a large percentage of the wellbore cross section is filled with water, reduced oil entry occurs. Performance simulations for these horizontal well indicate 30 to 50 percent productivity reduction when they are compared with their full potential.

P. 227

Drillstem Testing, drillstem/well testing, formation evaluation, horizontal well, interpretation, module, packer, Performance Evaluation, permeability, Probe, production control, production logging, production monitoring, productivity, regime, reservoir description and dynamics, Reservoir Surveillance, tool, Upstream Oil & Gas, water, well, wellbore

Gunasekera, D. (GeoQuest) | Childs, P. (GeoQuest) | Herring, J. (GeoQuest) | Cox, J. (GeoQuest)

Abstract

Multi-point flux discretization schemes for triangular, 2D perpendicular bisection, tetrahedral, 3D perpendicular bisection and comer point grids have been presented in the past by Aavatsmark and Verma in several papers. This paper presents a single implementation based on the ideas in the above papers for general 3D structured and unstructured grids, regardless of their method of construction. In this work, multi- point flux (MPF) coefficients are calculated only for cell faces that exceed a K-orthogonality error limit and are supplied to the simulator as an additional list of transmissibilities.

Following a construction or a conversion, all grids are stored in a general unstructured grid data model, where a grid is a collection of cells, a cell is a collection of faces and a face is an ordered list of points. The surface of a cell face is described by the set of triangular facets created by joining the centroid of the face to its edges. Externally generated corner point grids are converted to this data structure before generating MPF terms, which may involve a face splitting step at faults. The permeability within each cell is allowed to be a full tensor at an arbitrary orientation. The K-orthogonality error is estimated at each cell interface and is used to select the transmissibility formula, which is either K-orthogonal type leading to a two-point flux or multi-point type.

The paper presents simulation results for a set of test examples, with and without the use of multi-point fluxes. Comparisons of accuracy and CPU times are also presented to provide an understanding of the efficiency of the scheme.

Technical contributions in the paper include the conversion of corner point grids into a triangular facet based model, an algorithm for calculating multi-point flux coefficients for general structured and unstructured grids and the handling of MPF terms in a simulator.

P. 253

cell, coefficient, connection, discretization, face, flow in porous media, Fluid Dynamics, grid, injector, interaction, MPF, multi-point flux, NNC, producer, reservoir description and dynamics, reservoir simulation, scheme, society of petroleum engineers, Upstream Oil & Gas, water, water saturation, well

SPE Disciplines:

Brady, J.L. (Arco Alaska Inc.) | Watson, B.A. (Arco Alaska Inc.) | Warner, D.W. (Arco Alaska Inc.) | North, R.J. (GeoQuest) | Sommer, D.M. (GeoQuest) | Colson, J.L. (GeoQuest) | Kleinberg, R.L. (Schlumberger) | Wolcott, D.S. (Schlumberger) | Sezginer, A. (Schlumberger)

This paper was prepared for presentation at the 1998 International Oil&Gas Conference and Exhibition, held in Beijing, China, 2-6 November 1998.

SPE Disciplines: Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)

Thank you!